O-lay, offshore pipeline and riser installation technology

For O-lay offshore pipeline and riser installation, welding and inspection is done onshore

The offshore pipeline and riser construction and installation technology described here is very different from the common offshore technologies used at present. By using the O-lay technology operational production costs can be reduced compared to the existing general methods of pipe laying offshore. With O-lay, the pipe laying operations will be faster than other methods used today. Pipe line installation of larger diameter pipe can be as fast as 25 km per day. Furthermore the technology is safer because there are less people working in the offshore environment and the offshore operations are done in a shorter period of time.
The bottleneck of welding and testing on the traditional lay-barge is not a procedure that is part of the installation process anymore. Welding and testing are done on an onshore construction site.

The main difference between the new, state of the art, patented O-lay system and the existing systems is that the total length of the pipe is welded, post weld treated and tested onshore on a site that is near the waterfront.  Depending on the local situation, series of "long pipes", with a length of 50 to 1500 meter, are produced and temporarily stored in the pipe yard till they are transported into the water.

Deformation in elastic area

The "long pipes" are welded together in the final pipe line string and then transported into the water. If needed the pipeline will be kept afloat with the help of floatation devices. From the floating pipe a large spiral will be formed with a diameter that is sufficiently large to prevent the pipe from deforming in its plastic area. To remain within the 0,2% strain of the steel, the diameter of the floating circle is 500 times the pipe diameter
(Example: A pipe with OD 20 inch (500mm) will form a spiral of 250 meter diameter).

Quality of welds and improved fatigue resistance

The O-lay technology has the great advantage that welding can be performed under optimal conditions. With traditional S-lay the pipeline is lowered in the water just after the welds are finished. This cools down the welds and the HAZ relatively fast and induces local area's with high tensile stresses. Due to cyclic stresses these local area high tensile stresses can initiate cracks in the material.  With O-lay there is ample time to cool the welds slowly and to apply post weld treatments like ultrasonic impact treatment (UIT), needle peening and weld toe dressing to improve the weld geometry. These applications increase the resistance against crack initiation when a cyclic load is applied.

Floating transport

The spiraled pipe can form a total length of more than 100 km pipeline. When the pipe spiral has reached its predetermined length, the whole spiral can be transported (with the help of tugboats as is shown in the photo below) to the place where the installation has to be done. When the spiral has arrived at the location where the pipe will be installed, the spiral shall be unwound and with the help of a special prepared vessel  be lowered to the seabed. This method of pipe line installation is especially interesting for water depths where the S-lay method is being used and also in very shallow waters.

In the picture a tug boat pulls the floating spiral.

Retrieving

Instead of installing pipe with the combination of S-lay and a spiralled pipe it is also possible to retrieve pipe from the sea bottom. Thereafter the pipe can then be transformed into a large spiral after inspection. In this way it is possible re-use the pipe again on a different location. This will reduce the costs even further and could be very interesting to use on very small oil or gas fields.

Tested

Several tests in laboratory and under real conditions (as seen in photo above) have shown that the method described is feasible for pipelines of all diameters.

Source:

http://www.o-lay.net/

Intelligent flexible pipe can improve tieback design

The oil and gas industry has used flexible pipelines since the 1970s. Several thousand kilometers have been manufactured, installed, and put in operation. Many things can be done to make flexible pipe "intelligent." This is demonstrated in a technical feasibility study for expanding the producing Tui oil field.

Though intelligent pipelines can take many forms, two significant and proven applications are integrated service umbilical (ISU) and integrated production bundle (IPB). The ISU combines the function of both an umbilical and flexible pipeline. The IPB is essentially the same as an ISU, with an added active heating component. Both are made of a core and an assembly.

The core of either is a standard flexible structure. Flexible structures are made of several different layers. Each layer performs a different function. The inner most layer, known as an interlocking carcass, acts to withstand any hydrostatic collapse. Next is a leak-proof plastic sheath, known as the pressure sheath. This keeps the bore fluid contained. The pressure vault acts to withstand the internal pressure of the bore fluid. Then there are two sets of armor wires cross-wound for torsional stability. These wires take any tensile loading of the flexible pipe. The final layer of a standard flexible pipe is a plastic sheath to prevent water ingress into the annulus between the two plastic sheaths.

The assembly can comprise a bundle of hoses, cables, steel tubes, optical fibers, and insulation wrapped around the core. Assembly components typically are used for gas lift, chemical injection, hydraulic lines, power communication cables, heat tracing wires, and more. The assembly is held together by high-strength tape and a plastic outer sheath.

Feasibility study

Intelligent pipeline benefits have been demonstrated in a technical feasibility study on a Tui oil field expansion. As part of this study, tieback solutions of a production flowline, umbilical, gas lift flowline, and gas export flowline are considered.

Tui is 50 km (31 mi) offshore New Zealand in the Taranaki basin. In operation since 2007, Tui was New Zealand's first standalone subsea development. As part of its subsea field layout, it comprises four wells linked to an FPSO.

Design data

The main criteria for design of the flexible structures in this case are a production flexible flowline, a gas lift flexible flowline, and gas export flexible flowline are as follows (courtesy AWE):

The umbilical components are part of a previous umbilical design supplied for the project, so each component has been qualified for its function. The feasibility study called for the following:

Solution

The base case would be to supply three separate flexible pipeline structures and one umbilical. The alternative is to combine the gas lift, production, and umbilical into one pipeline known as the IPB, resulting in the manufacture, supply, and operation of only two pipelines.

In this case, the production line forms the core: the gas lift and umbilical form the assembly. The advantages of an IPB in this situation are reduced installation time, reduced field complexity, and optimized thermal performance.

Reduced installation time and reduced complexity arise because there is one structure instead of three. Reduced installation time is especially beneficial in this case because the Taranaki basin is known for harsh weather. The reduced complexity of the field means fewer pipes on the seabed and a cleaner subsea layout. This is advantageous for fields with existing infrastructure. Optimized thermal performance comes because the gas lift tubes are integrated into the structure. So, where the production line would have the highest temperature, the gas lift would have the lowest. Optimized thermal performance might keep the production line above a critical value to mitigate hydrate formation.

The Tui oil development is offshore New Zealand.

The IPB design is made up of a standard rough bore (with interlocking carcass) structure which forms the core and an assembly. The assembly consists of six thermoplastic hoses, two cables, and four steel tubes. The thermoplastic hoses can be used either for chemical injection or hydraulic controls. The cables are used for power and communication to subsea equipment, and the 3-in. gas lift line is split into four 1-in. steel tubes. All these components are evenly distributed around the flexible pipe for torsional stability, and are separated by fillers. Fillers keep these components in place as well as transfer any mechanical loading to the core. Both fillers and components are wound in an S-Z manner around the core of the flexible pipe resulting in torsional stability of each of these components.

In detailed design, the following options might bring advantages in cost savings and/or enhanced performance. These include the following:

• Similar outer diameter components
• Adding passive insulation
• Active heating
• Temperature monitoring.

The use of similar outer diameter components allows the use of one filler type. This reduces the manufacturing complexity of the flexible pipe structure. Passive insulation takes the form of strips of synthetic foam which can be added as part of the assembly.

Active heating

There are three ways to provide active heating to a flexible pipeline: hot water circulation, the use of heat tracing cables within the armor layer, and/or a dedicated active heating section above the core of the flexible pipe. Active heating is useful where hydrate formation is an issue and the bore fluid has to be kept above a critical temperature. It is especially useful for shutdown and restart operations.

Hot water circulation is beneficial because the hot water is warmest where it is injected, which is where the production line is coldest. This can mean an increase in diameter, which is not optimal. This makes the use of heat tracing cables advantageous.

Heat tracing cables replace every few tensile armor wires. The number and location of these cables depend on the heating requirements, and those are governed by factors such as water depth, length of pipeline section, bore fluid temperature, and critical temperature of the bore fluid. If the design of the flexible is governed by tension, a dedicated heating layer above the core of the flexible pipe can be created. The design of the heat tracing cables is unique in the sense that it is a three-phase star connection circuit, which means that the sum of the current phases is nil. Therefore, no return cable is necessary, ensuring a more compact solution.

Temperature monitoring

Technip's temperature monitoring is the distributed temperature sensors (DTS) system. This provides continuous temperature measurement along the length of flowline using optical fibers.

Small bore stainless steel tubes are incorporated in the tensile armor layer during manufacture. Every fourth tensile armor wire is replaced by a steel tube, sometimes with plastic fillers on either side to ensure structural integrity of the steel tubes. At one end fitting termination, the steel tubes join to provide a continuous loop. Post manufacture, the optical fiber is inserted into these steel tubes using a blow down technique.

This involves the use of fluid drag to run the fiber through the control line. A pump pressurizes the system, the tubes provide the drag, and the fittings allow fluid to flow through the system, directing the fiber in the line. The loop in the termination allows the optical fiber to be inserted at one end and retrieved at the other end. This means there is access to both ends of the optical fiber. Double-ended measurements can then be made with no fiber splicing, thereby increasing the accuracy of the measurements.

DTS sends pulses of light down the optical fiber. The ratio of intensities of the two wavelength separated components of the back scattered light yields the temperature at the point of scattering. The time it takes from when the pulse is sent and to when the back scattered light returns gives the location of the temperature. As a result, a temperature versus distance graph for the whole length of the optical fiber can be constructed. The principle is known as Raman OTDR (optical time domain reflectometry).

Graphical user interface

A dedicated system can be created according to project requirements to facilitate the user interface of the system. This can consist of obtaining raw data along the length of the riser system. This can then be split into critical locations along the length of the riser such as touchdown point, gas-lift injection point, and topside. Other functions can be implemented into the system such as alarms in case of detection of cold or hot spots to prevent against hydrate formation and temperature fluctuations in the flexible pipe.

3D representation of an IPB (left). Cross section of an IPB (right).

Gas export line

The nominal option of the 4-in. gas export line is a standard flexible pipe structure. However, with the use of intelligent options such as active heating, the need for dehydration of gas prior to export onshore could be revisited. This would be useful where there is no offshore processing facility. Active heating could take the form of electrical heat tracing cables integrated into design of the flexible pipe.

3D representation of an IPB (left). Close up of the DTS system (right).

Qualification and track record

Integrated service umbilicals (ISU) have been used for a number of years. The current record stands at 18. A number of tests have been performed to determine the validity of these intelligent pipeline solutions. These take into account the mechanical behavior of the pipe when subjected to installation loads and hydrostatic loads, the thermal behavior of the pipe due to the integration of active and passive heating, and fatigue behavior of the pipe.

The first test began in 1998-1999. A test sample was fabricated incorporating active heating by hot water circulation. The sample consisted of an 8-in. ID flexible pipe with 11 hoses distributed around the core and passive insulation in the form of 30 mm (≈1.2 in.) of syntactic foam above. This was subjected to several heating and cooling phases. This qualification program resulted in the development of calibrated software in which the global heat exchange coefficient (U-value) of an IPB can be determined accurately as well as software capable of modeling the thermal and hydraulic coupling of an IPB, verifying its performance with regards to flow assurance.

In 2000, a joint industry research and development program (JIP) was formed between Technip and participants to qualify active heating for a flexible pipe. As part of this JIP, two electric heat tracing technologies were tested. The sample incorporated two designs - heat tracing cables as part of the assembly (dedicated heating layer) and heat tracing as part of the armor wires. The sample was then submerged in water and subjected to more than 10 different heating and cooling simulations. Test results were used to validate the design of the IPB as well as software used to design the IPBs.

The JIP also led to the creation of the DTS, which was devised to monitor the temperature along the length of the flexible pipeline during the test. The DTS system was integrated into the test sample as part of the tensile armor wires as well as part of the bundle layer.

Previously manufactured IPBs.

To complement thermal testing, a full-scale test was done to study the behavior of electrical cables laid in an SZ manner over a core structure. It was found that the dynamic fatigue cycling as well as the heating and cool down phases had no effect on the integrity of the electrical systems. A layer by layer dissection found no significant damage to any of the IPB components.

The JIP paved the way for its first application offshore West Africa. This project is in block 17, 135 km (84 mi) offshore in water depths of between 1,200 m (3,936 ft) and 1,500 m (4,920 ft). For this project, eight 10.75-in. IPBs were supplied. The IPB design consisted of six heat tracing cables, thermal insulation, DTS system, and 24 gas lift tubes evenly distributed around the core of the IPB. A test sample was manufactured prior to final supply which was subjected to a full-scale testing in which the crushing, fatigue and thermal behavior was validated. A full-scale test was performed in a vertical configuration as this is more representative of real-life conditions.

Conclusion

With discoveries in more challenging fields, the implementation of intelligent pipelines is a qualified solution for both new and existing fields. These intelligent pipeline solutions take the form of an integrated service umbilical (ISU) and integrated production bundle (IPB) which can incorporate umbilical functions, active heating components, and the DTS system.

Key advantages of intelligent options can include improved thermal performance, reduced complexity of existing fields/new fields, and minimized installation time. Improved thermal performance can be achieved several ways where the temperature of the bore fluid needs to be kept above a certain critical value. The reduction in complexity of a subsea field layout and minimized installation time arises from incorporating three different flexible structures (gas lift, production, and umbilical) into one pipeline solution.

The ISU design has been in service for many years. IPB is a more recent technology. The IPB is qualified by numerous test programs performed by Technip, which validates the performance of its active heating elements and DTS system. The positive results of these test programs have paved the way for its use on offshore projects; the IPB risers have been successfully implemented on two West Africa field developments and are due to be installed on a project in Brazil.

Integrating seafloor studies for pipeline routing

The principles of geometry state that "the shortest distance between two points is a straight line." Companies responsible for building pipelines on the continental slopes of our oceans only wish that this law could be applied. Rarely are operators provided the luxury of simply reviewing the sea-bottom from Point A to Point B and then installing a pipeline in a straight line.

The seafloor and near-seafloor geology are typically too complex or constraining to build such a steel lineament. It requires considerably more pre-planning when first deciding where to install a pipeline relative to Point A and Point B. When conducting a pipeline study there are generally four major steps that a design team should consider and implement:

• Review existing regional and site specific data in the area
• Plan a preliminary pipeline corridor
• Conduct a detailed high-resolution geophysical/geotechnical study
• Integrate the geophysics, geology, and geotechnical soils engineering results.

Integrating studies

Mariner Energy Company used a similar approach to the successful design of their Dulcimer Pipeline Project extending from Garden Banks Block 367 to Block 236. Geoscience Earth & Marine Services (GEMS) conducted the preliminary study for this and further completed the interpretations of the final geophysical data collected on the pipeline corridor survey. Intec Engineering was involved in the pipeline design and project management of this study; C&C Technologies conducted the field geophysical operations; Marsco conducted the geotechnical study.

The pipeline route is just west of Geyer Bank, a carbonate hard bank on the upper Louisiana continental slope. Rock outcrop, seafloor faults, expulsion mounds, and other seafloor features extend westward from the Bank. All of these geologic features caused deep concern in selecting a final and feasible route for pipeline deployment.

The direct route approach (Point A to Point B) would have been 64,484 ft in horizontal length. The actual survey showed that the pipeline must be routed around seafloor fault scarps, hard bottom conditions, and seep mounds which increased the horizontal pipeline length to 73,977 ft. The final pipeline corridor had to weave around several constraining geologic conditions The preliminary study greatly reduced the amount of time spent in the field to locate the appropriate route.

Water depths along the pipeline route range from 675 ft to 1,270 ft below sea level with variable gradient ranging from 1% to greater than 40%. Changes in elevation along the route only increased the pipe length by 0.02%, to a total length of 73,993 ft.

Review existing data
There generally is some information available on the regional morphology, seabed character, soils, and man-made infrastructure in an area where production and subsequent pipelines are planned. Too many times, however, this information is overlooked in pipeline route planning.

When pre-planning a pipeline corridor, the planners should consider what work has been previously done in the area, and how much, if any, of this data can be applied to the study. Public information, as well as proprietary data, is generally available in many areas of the world. In the Gulf of Mexico, for example, it is relatively easy to research and find which companies hold the rights on Federal OCS lease blocks, and what man-made infrastructure exists in the general vicinity of the planned pipeline route.

It is equally easy to determine if any high-resolution geophysical surveys have been completed over these lease holdings. Operators can be contacted to request use of such information in the planning of the route. The best interest of the operator may be achieved by working with the pipeline company to plan a feasible corridor for investigation of a route that will fit with the leaseholders plans for development (if any).

In many cases, the original or copied high resolution data is not always available from these surveys. However, the final geohazards reports are relatively easy to obtain either from the operator or from the public information files archived with the US Minerals Management Service (MMS), in the case of the US offshore. The information gleaned from these reports can be compiled into one complete sketch of the seafloor to define the bathymetric and geologic conditions across the corridor.

Other data
Regional data, such as swath bathymetry, and dense data sets such a 3D seismic, can be quite helpful when used properly. When these swaths of data have been collected in over lapping footprints, the resulting data file is a very dense sounding file of the seafloor topography.

Bathymetric maps and profiles can be generated to provide detail of subtle highs and lows along the seabed. The regional bathymetry and profile generation can assist the planners in eliminating terrain that does not look conducive to pipeline installation.

Depending on the density of data, an x,y,z-file of the seabed can then be rendered using one of many imaging software packages to produce a picture of the seafloor terrain. These renderings can provide a very detailed image of the topography, illustrating seafloor irregularities such as: fault scarps, slope instability failures (landslides), hard rock conditions, mounds, vents, chimneys, and other features that would cause concern to pipeline design.

3D seismic
Regional swath bathymetry is not always available over the area to be investigated. The operator may, however, have available 3D seismic data that can be used to pick the seafloor return and produce a similar bathymetry map and seafloor rendering.

Three-dimensional seismic data is generally of very high-quality, and dense coverage (bin-spacing generally 12.5 to 25 meters/bin), so that the seafloor is well represented. In addition, the amplitude of the seafloor can be sampled from these data and a rendering of high-amplitude seabed features can be illustrated.

These high-amplitude events generally show areas of hard bottom and/or areas of fluid venting at the seafloor. In the deep waters of the Gulf of Mexico, these vent and hard bottom areas can, be home to chemosynthetic communities.

Survey corridor
When the existing data is adequate, a map can be generated with all known water depth contours, geologic features, and man-made infrastructure. This map can then be used to select a preliminary pipeline corridor to avoid any potential obstructions. Multiple corridors may be selected depending on geologic and man-made obstructions, seafloor slope, pipe length, turns, crossing angle to other pipelines, and other features. Preliminary pipeline corridors may go through many iterations before settling on feasible routes to investigate.

Sometimes, the regional data is not sufficient to select a confident pipeline corridor. This can be especially true in remote areas of the world. One way to overcome this obstacle is to conduct your own area survey. The collection of swath bathymetric data can be done quickly over the area, and can be done with the same survey vessel contracted to perform the pipeline corridor.

Final contour maps, profiles, and renderings can be produced directly on the ship. Qualified geologists and pipeline engineers can select a feasible pipeline corridor directly on the vessel. The corridor can then be surveyed by the same vessel during the same field activity with the high-resolution geophysical suite of equipment.

Field survey

• Geophysics: Once a survey corridor is planned from the review of existing data and/or from the acquisition of swath bathymetry, the next step is to complete the high-resolution geophysical survey. The number of survey lines and line spacing required for the survey depends on the type of lay-barge and/or method of pipe-laying operations. For instance, if a dynamically positioned lay barge is to be used, then an area of approximately 400 meters on a side from the proposed pipeline route is recommended. If an anchored lay-barge is utilized, the survey coverage should extend outward from the barge to the extent of anchorage. The data collected should consist of continuous echo-soundings, or better yet, full swath bathymetry, side-scan sonar imaging of the seafloor, subbottom profiling of the upper 50-100 ft of sediment, and magnetic detection. The benefits of the previous steps is to acquire only the amount of high-resolution geophysical data needed to define the final route.
• Geotechnics: The onboard geologist should map the geologic features during the acquisition of the geophysical data. The geologist and geotechnical engineer should then communicate on the seismic variation in seafloor character to select locations for soil sampling. Piston drop cores and in situ tests collected along the route assist to "ground truth" the geologic interpretations. The collected samples can then be returned to the soils laboratory for further testing.

Traditionally, shallow drop-core samples are taken at intervals along the pipeline route to define the soil properties. Since the pipeline support is essentially influenced by the upper two meters of sediments, it is important that good soil data be acquired throughout this zone.

Pipeline trenching and burial for thermal insulation is another consideration that may need to be studied. Special in-situ tests should also be conducted during the field program in order to provide geotechnical parameters for subsequent design of equipment if trenching and burial is a consideration.

Integrated results
The final step in a pipeline study is to integrate all phases of work into a single, concise geologic model that defines the seafloor and subsurface conditions, and describes that model in a report that is understandable by all members of the pipeline team responsible for the safe installation and use of the pipeline.

The interpreted geophysical/geotechnical data defines an integrated geologic/soil model in three dimensions along the entire pipeline route. Basic interpretative maps can include:

• Bathymetry and seafloor gradient
• Seafloor topography, such as seafloor mounds or fault scarps
• Basic geologic features such as faults, shallow gas, and hydrates
• Soil provinces including variations in geotechnical properties
• Manmade features or debris
• Areas occupied by chemosynthetic communities
• Areas of seafloor instability.

Thus, the final route can be selected with a complete understanding of seafloor conditions (topography, geology, and soils) to avoid regions of irregular seafloor or difficult geologic conditions such as rock outcrops, fault scarps, and other features. Pipeline designers will use the seafloor topography and soil properties along the route to address such design considerations as spanning, settlement, and stability (sliding or erosion of the soils providing the foundation support).

In addition, the topographic data and three-dimensional soil model may be used by the geotechnical engineer to quantitatively assess the slope stability in areas with the steep seafloor gradients. The integrated data will also help select the most favorable site for subsea installations and anchors for a floating production system.

Conclusions
The phased approach to deepwater routing studies provides many technical and financial benefits if performed in a systematic and logical order. The Dulcimer Project illustrates the benefits derived from this approach:

• Existing data is used to the maximum extent to define the complexity of the geologic setting
• Multiple routes can be selected and studied before settling on the more feasible route to be surveyed
• Provides preliminary information to pipeline designers before any survey data has been collected
• Limits the amount of additional geophysical and geotechnical data required
• Decreases geophysical and geotechnical field time, thereby reducing field costs
• Provides a concise geologic/soil model that defines seafloor and subsurface conditions for all pipeline design team members.

The phased approach allows pre-planning with existing data and avoids unnecessary field work, which ultimately saves time and money on deepwater pipeline route surveys

Source:

http://www.offshore-mag.com/articles/print/volume-59/issue-6/departments/technology-focus/integrating-seafloor-studies-for-pipeline-routing.html

Innovative engineering solves subsea pipeline tie-in challenge

Technip was recently contracted by Burullus Gas Co. (Burullus) to tie in an expansion to its existing subsea West Delta Deep Marine (WDDM) facilities. To accomplish this, it was necessary to tie in a new 36-in. gas trunkline pipeline, which is part of the Phase VII project, to the existing system under pressure without shutting down production. To perform the tie-in, Technip retained T.D. Williamson S.A. (TDW) to carry out three subsea hot tap intervention operations.

Two traditional 16-in. hot tap operations would be completed on a 26-in. pipeline, and one innovative 20-in. hot tap on a 36-in. pipeline. To ensure that the hot tap interventions would be successful, it was necessary to engineer, install and pre-commission two hot tap assemblies, including one capable of cutting through a blind weld-neck "tappable flange" made of duplex stainless steel on the 36-in. line.

Hot tap machine

In preparation for the operation that would take place in depths to 95 m (311 ft), TDW worked with a Belgium-based engineering and construction specialist to produce the special hot tap tool known as a "cutter." This special tool would be used for the 20-in. hot tap and would need the ability to effectively cut the duplex plate. Since the duplex has a very high mechanical strength – meaning that it has a high elongation before reaching breaking point and a high level of hardenability – the cutting process employed must be very rigid and vibration-free while using the TDW Model 936D subsea tapping machine.

TDW's customized subsea tapping machine onboard the dive support vessel Wellservicer.

Working at TDW's facility in Nivelles, Belgium, a series of engineering, design and preliminary tests was performed. The first step involved engineering several alternative designs. The first alternative consisted of using either a proven cutter design; or that proven design updated with various teeth geometry. However, this option was not pursued because it could not penetrate the duplex stainless steel.

TDW's customized subsea tapping machines onboard the dive support vessel Wellservicer prior to the operation.

A second option involving removable teeth and welded teeth support was considered, but this was rejected due to its inability to resist vibration.

Ultimately, the design selected for fabrication featured a subsea electro-pump to supply adequate hydraulic power, a pilot drill with bronze plates to reduce vibration, and a specially manufactured set of cutters with removable cutting teeth that would be able to penetrate duplex stainless steel without breaking.

Preliminary trials

After the design was finalized, materials were procured and the prototype was fabricated and made ready for the first phase of testing: the internal preliminary trials.

A diver prepares for the vertical hot tapping operation.

During a period of eight weeks, the prototype was subjected to rigorous testing associated with a number of capabilities. The cutter's ability to make deep cuts on a plate of the same type of duplex stainless steel as the blind weld-neck "tappable flange" on the pipeline was an initial challenge.

A diver carries out the horizontal hot tapping operation.

The team made material and design improvements, ultimately achieving a prototype that could produce a smooth and satisfactory cutline. In addition, special bronze guides were developed and installed on the pilot drill to control vibration.

By the end of the four-month trial period, several renditions of the prototype had been used to complete four tapping operations. Before and after each cutting trial, visual and nondestructive examinations (NDE) of the cutters and pilot drills were carried out. The final prototype, which featured dual sets of cutting teeth and the pilot drill with the bronze guides, performed well. As the hot tap machine would be required to operate at an average pressure of 100 bar, pressure tests were undertaken to satisfy the requirements of the forthcoming factory acceptance test. The decision was then made to proceed to the second stage: the official trials.

Official trials

During the official trials three tapping operations were carried out with the custom machine. Two hot taps were completed on duplex plate, and one cold tap was executed through equal duplex tappable plate. These tapping operations revealed that the equipment endured the rigorous process, remained properly aligned and cut the duplex steel plate effectively. These operations took place as part of a requisite system integration test (SIT), which confirmed the following:

• The teeth accurately cut the duplex stainless steel
• The pilot drill remained rigid and vibration-free
• The design of the cutter was improved by adjusting the teeth support.

It also proved that the tapping machine could be unset in the middle of the cut and reset while reaching the cut back without causing the tapping machine to be misaligned or moved out of proper position.

With the official trials of the custom hot tap cutter successfully completed, the system received approvals from Burullus, Technip, and the Burullus Independent Verification Authority to perform the subsea operation well in advance of the project mobilization. In preparation for the impending operation, two hot tap machines were produced in order to guarantee 100% back-up of this critical piece of equipment.

Maintaining gas pressure

For three weeks, TDW worked from Technip's dive support vessel Wellservicer to carry out all three hot taps. Throughout the process, a prevailing pressure of 100 bar (1,450 psi) was successfully maintained in the existing gas export system. The innovative hot tap on the duplex tappable flange required just six days to complete.

In spite of the fact that the hot tap intervention was carried out subsea, making it more complicated to mobilize and install equipment than when working onshore, the operation was carried out by skilled divers as intended, with no lost time incidents or production downtime.

Much of the success was attributed to the investment in planning and pre-operational equipment trials and testing. TDW worked with the Technip and Burullus teams to ensure that the operation would proceed like clock-work, and that the customized cutting tool would operate effectively on duplex stainless steel. As a result, the operation provided three tie in points, preparing the way for Technip to successfully tie-in the new 36-in. gas trunkline for the WDDM Phase VII development.

Source :

http://www.offshore-mag.com/articles/print/volume-71/issue-11/flowlines-__pipelines/innovative-engineering-solves-subsea-pipeline-tie-in-challenge.html

Gas flows and pressure maintained during North Sea pipeline hot tap

Acergy was responsible as lead contractor for project management and engineering of a subsea hot tap tie-in of the Ettrick field North Sea gas export pipeline operated by Nexen Petroleum UK Ltd. to allow production to be exported to a gas plant north of Aberdeen, UK.

A unique aspect of the hot tap was that the operating pressure of the pipeline was potentially 172.3 barg, higher than any previous hot tap on or offshore. This meant that two custom hot tap machines with a pressure-balance capability of 172.3 barg would have to be designed and manufactured.

Acergy’s scope was to engineer, procure, install, and pre-commission the hot tap assembly, in addition to supplying the temporary and permanent subsea structures. Acergy retained T.D. Williamson SA (TDW) to provide specialist services to support the subsea hot tap operation.

Hot tap paves way

Shutting down a live gas pipeline is costly and time-consuming. Hot tapping was developed as a safe method of trepanning - or drilling into - a pipeline without shutting it down. "Hot tapping" is the process of drilling into a live, onstream piping system without any content release or flow interruption.

The first step in hot tapping is to secure a hot tap fitting onto the pipeline. A permanent valve is attached to the fitting. The hot tap machine then is installed on the valve, and the valve is opened. Finally, the entire assembly is pressure-tested.

Cutting commences using a pilot drill to steady the cutter and to capture the cut pipe - or coupon. The hot tap machine fills with product and all air is purged from the housing. The main tap then is made through the pipeline with the requisite size hot tap cutter, after which the coupon is removed. The valve is closed and the hot tap machine recovered. A spur line then can be installed. When the valve is opened, the new connection is put into service.

In this instance the operator needed to access the line in order to tie-in the gas export line without shutting down the flowing pipeline.

Unique challenges

The pipeline transports approximately 20% of the UK’s gas supply. Any problems arising from the hot tap operation could potentially shut down the pipeline, halting the gas supply and oil production in a large number of oil fields. This would have a major impact on the UK economy. Therefore, it was necessary to demonstrate the highest levels of assurance on all critical elements of the job. These critical elements were:

• Welding and non-destructive examination (NDE) of the branch connection
• Installation of the protection structure
• Hot tapping the pipeline.

Acergy was in the challenging position of satisfying the stringent integrity requirements of the operator, while working against an extremely tight timeline. In preparation, a meticulously-planned schedule of activities was embarked upon to ensure that the subsea hot tap operation would be a success.

Preparations provide assurance

For five months commencing August 2008, equipment development, testing, and operational trials began at TDW’s facility in Nivelles, Belgium. Its top priority was to design and build the custom hot tap machines. It would be the first such pressure-balanced subsea hot tap machine manufactured by the company’s European arm. Following analysis of the targeted pipeline, designs for the machine were finalized. Materials were procured and production was launched. Because the new hot tap machines were to be pressure-balanced to 172.3 barg, TDW hydraulically tested them to 258.6 barg. In addition, the seals were gas tested to the same pressure to ensure that they were tight, and would retain their integrity during the hot tap. These pressure tests met the Factory Acceptance Test requirements. Because the machines represented a new design, a failure modes and effects analysis (FMEA) also was carried out.

The hot tap machine inside the temporary installation frame at the SIT in Methil.

The two identical pressure-balanced hot tap machines were manufactured to provide 100% back-up of this critical component. Designed with the requisite pressure balance capability, the machine interfaced with the hot tap valve. The system was powered by a subsea electro-hydraulic unit via umbilical cable housed on a double-drum cable spooler. The hot tap machine is controlled by technicians at an electrical control cabinet on the dive support vessel. In addition, five hot tap cutters and five pilot drills were supplied with each system as contingencies.

The Acergy Osprey mobilizing for the Ettrick field hot tap operation.

A two-phase, factory trial was conducted at the National Grid Gas facility in Ambergate, UK, to determine the system operating parameters. Phase 1 involved a series of nearly 24 test cuts to prove the durability and reliability of the cutters and pilot drills. Visual and NDE inspections of the hot tap cutters and pilot drills were done before and after the cutting. The second phase consisted of hot tapping actual sections of the 30-in. (76-cm) diameter (OD) construction pipe to ensure equipment endurance, alignment, and cutting effectiveness.

The hot tap machine lowered to interface with the hot tap valve during the SIT.

In conjunction with the Ambergate trials, the actual hot tap dive team underwent an orientation with the hot tap machine and system components.

Subsea operation simulated

To further confirm the integrity of the custom hot tap equipment, a System Integration Test (SIT) simulated a full hot tap operation in Methil, UK. From an equipment perspective, the primary SIT objective was to verify that all custom components fit together and operated according to the design.

The hot tap simulation was carried out in the 90-ton (82-metric ton) custom-made protection frame on a pressurized test vessel. The hot tap machine was set for optimum operational parameters derived at the factory trials. Using a welded hot tap assembly identical to the eventual hot tap branch nipple and sleeve and welded onto a section of the actual pipeline to be tapped, the assembly was positioned in the protection structure. Acergy divers operated the hot tap machine, allowing the pipe section to reach the level of pressure that would most likely be reached in the live pipeline offshore.

The SIT demonstrated that:

• The system did not leak and accurately cut the pipe
• The coupon was retained on the pilot drill
• The hot tap machine remained pressure-balanced throughout.

Subsea hot tap operation goes to plan

The hot tap was to be carried out at approximately 94 m (311 ft.) sea depth on a development in the outer Moray Firth. In June 2008, Acergy installed the hot tap assembly, which consisted of a 12-in. (30.5-cm) bore-welded nipple and bolted reinforcement configuration. Once the protective frame and pressurized dry habitat were placed on the seabed, operations began. In July 2008, the hot tap team mobilized to the hot tap site. Working from the Acergy Osprey dive support vessel, two technicians consulted with the divers around-the-clock via images from cameras on the divers’ helmets and an ROV. The team also monitored for bubbles which could signal a leak.

The entire offshore hot tap phase was nine days. Of that, the actual hot tap was completed in one day. Trepanning, which allowed for all valve tests and pressure testing of the assembly, lasted just over seven hours. The program went as planned with no Lost Time Incidents or production downtime. The cutting operation went smoothly, and technicians removed and recovered the 12-in. (30.5-cm) pipe coupon and hot tap machine to the Acergy Osprey. A piping-valve assembly was attached, providing two tie-in points: a 6-in. (15-cm) tie-in to the adjacent field and a 12-in. for a future tie-in.

Throughout operations a prevailing pipeline operating pressure of 117 barg (1,096 psi) was maintained and hydrocarbons flowed at normal rates.

Considerable challenges were overcome. By producing a hot tap machine with the highest pressure-balance capability ever developed, the team broke the pipeline’s integrity in a controlled manner, allowing pressure to remain steady.

The second major hurdle was to satisfy the high technical integrity requirements of the operator on a very tight schedule. A series of carefully planned and successfully executed tests and trials resulted in a successful subsea hot tap operation, paving the way for the Ettrick field gas export pipeline tie-in.

Source :

http://www.offshore-mag.com/articles/print/volume-69/issue-8/Flowlines___Pipelines/gas-flows-and-pressure-maintained-during-north-sea-pipeline-hot-tap.html

Underwater Welding Hyperbaric tests probe potential for arc welding below 1 km depths

Recent research into hyperbaric welding technology in depths ranging from 500-1,000 metres has been performed at several leading European research centres, such as GKSS and Universitat der Bundeswehr in Germany, Sintef and Cranfield University. Overall consensus of these programs is that two arc welding processes can be effectively operated in this depth range: plasma welding and gas metal arc welding (GMAW).

Cranfield's Hyper-Weld 250 pressure vessel

Plasma welding is a derivative of gas tungsten arc welding (GTAW) in which the arc, instead of being allowed to spread freely, is constricted within a water-cooled orifice. This reduces the cross-sectional area of the arc, increasing arc temperatures and stability. However, a significant drawback of this technique is that the performance of the arc is influenced by a large number of variables, including the internal geometry of the welding torch.

Plasma welded butt joint in 1-in. thick X65 pipeline steel made at a pressure of 100 bar

Cranfield has recently completed a major research program into hyperbaric plasma welding, and has demonstrated that the plasma arc remains stable to pressures equivalent to 1,000 meters water depth and can be reliably initiated at that pressure.

In surface welding, plasma arcs are used in two ways. If operated with relatively large diameter constrictions and minimal setback of the tungsten orifice behind the constriction, they perform similarly to GTAW arcs, but are more stable.

Typically, a plasma arc operated this way will develop arc voltage about 10% higher than a free burning arc in similar conditions. Such arcs have been used with a consumable feed system to produce test welds at pressures as high as 100 bar, equivalent to 1,000 metres water depth.

When welding at one atmosphere, if the power density of the plasma arc is increased by reducing orifice diameter and raising electrode setback and plasma gas flow, the arc can then operate in the `keyhole' mode, producing weld beads which are much deeper than they are wide.

Keyhole welding was not thought to be feasible under hyperbaric conditions, but recent work at Cranfield and Hamburg has produced keyhole welds at pressures equivalent to depths below 300 metres. If the technique can be shown to be operationally feasible, the consequences for root welding of pipelines could be significant, as it would enable high integrity welds to be performed much faster than by other techniques.

Gas metal arc welding was originally evaluated for hyperbaric applications in the mid-1970s, when the low fusion levels attainable by the process were deemed unsuitable for offshore use. However, the closely allied flux cored arc welding process (FCAW), using a tubular configuration electrode, was successfully applied in hyperbaric environments.

The recent emergence of high performance, electronically controlled welding power supplies has led to re-evaluation of the process, and the development of special welding power supply control systems by Cranfield and by GKSS for hyperbaric GMAW.

These units control the static and dynamic output characteristics of the welding power supply in order to optimize the stability of the GMA welding process. Using such control systems with high performance welding power supplies, GMAW has proven capable of all positional operation, with acceptable stability and fusion levels at pressures equivalent to below 1,000 metres.

Although special power supply control systems are necessary for deepwater hyperbaric GMA welding, they do not raise the cost of the welding system significantly: standard high performance welding power supplies can be used to supply the actual welding current.

However, more research is needed to develop effective torch manipulation and joint filling strategies for practical weld geometries. The process also currently develops significant welding fume, and other welding variables such as the shielding gas composition need to be optimized. But there is considerable experience in industry generally with GMAW for robotic welding, and this process may be appropriate if similar robots are used in hyperbaric workchambers.

The current state of hyperbaric welding is therefore that operational systems exist capable of operating at 500 metres water depths. In the depth range 500-1,000 metres, laboratory research has shown that at least two arc welding processes are capable of consistent and stable operation, although only preliminary investigation has been made of mechanical and metallurgical properties of welds employing these techniques.

In order to continue this development process for water depths exceeding 1,000 metres, experimental facilities are needed with appropriate operating pressure capability. Cranfield is currently commissioning HyperWeld 250, a hyperbaric welding research facility operable at a maximum pressure of 250 bar, equivalent to 2.5 km water depth, funded by the Engineering and Physical Sciences Research Council acting through the UK's Marine Technology Directorate.

This is believed to be the highest pressure dedicated welding research facility in the world. The pressure vessel and gas supply system were specified by Cranfield, with detail design and construction by Stansted Fluid Power. The welding power supply system, designed with Austria's Fronius Schweissmaschinen, can supply 500A at over 200V, with an additional 50A supply capable of 700V output.

The overall facility control system is being developed with Isotek, a supplier of control equipment for hyperbaric welding systems such as PRS and THOR. Additional design studies are being undertaken relating to arc viewing systems, welding torches, data logging and analysis systems.

Currently, a large, multi-sponsored managed programme of deepwater arc welding feasibility studies is being formulated, scheduled to start early in 1996. This will initially carry out the process feasibility studies described earlier, probably in the depth range 1,000-1,500 metres, and will be extended even deeper as results permit.

Initial welding trials will be performed on flat plate material in all welding positions, but the system has been designed to permit installation of an orbital welding system later on.

Source:

http://www.offshore-mag.com/articles/print/volume-55/issue-12/news/production/underwater-welding-hyperbaric-tests-probe-potential-for-arc-welding-below-1-km-depths.html