RIGID PIPELINE INSTALLATION
There are 2 types of rigid pipeline installation that I have been involved; S-Lay & J-Lay. Both of the lay process contains the same the installation process.
S-Lay:
Shallower water
J-Lay:
Suited for deeper water pipelines, this method utilizes a near vertical mast to stalk on additional pipe joints as the lay barge moves ahead. The pipeline does not have an overbend section as it transitions from the near vertical to the seabed. A sagbend near the seabed provides the shape from which the lay method’s name is derived.
LOAD-OUT AND TRANSPORTATION
A) GENERAL
Early selection of the transportation barges will be advantageous to allow timely completion of transportation engineering and rig-up. Brief outlines of the basic requirements for barge selection and transportation design to suit line pipe transportation are as follows.
– Barge size should be maximized to reduce the number of spreads used.
– Barge to have sufficient bollards all around to provide adequate mooring points during the pipe handling and lifting operations offshore.
– Space should be set aside for transportation of consumables and appurtenances.
– Size (particularly length) of selected pipe transport vessels should be compatible with the laybarge where possible.
– Certification of pipelay vessels should be current and in accordance with contract requirements.
B) LOAD-OUT CONSIDERATIONS
The responsibility for the loadout of the line pipe is normally split between the pipe coater and the transporter depending on the contract. The pipe coater will transport the line pipe to the wharf and load out the line pipe onto a barge provided by the transporter. The transporter will ensure that the barge has adequate dunnage and stanchions to receive the pipe, and provide sufficient material and labor to tie down the line pipe for transportation. The Field Engineer or other nominated Operations Department representative (Loadout Coordinator) should attend each load out to ensure that the following requirements, as a minimum, are met:
– Checklist of marine requirements for the transportation barge, i.e. mooring bollards, navigation lights, ballast condition, etc.
– Checklist of line pipe required, i.e. number of plain, anode and marker joints. Line pipe to be stacked to suit the installation sequence.
– Ensure that the line pipe is protected against salt spray corrosion, especially on long tows.
– Checklist of consumables required, i.e. pallets of mastic, foam chemicals, etc.
– Produce list of all deficiencies originating from the coating yard at custody transfer, i.e. damage reports, missing material, etc.
– Obtain tally sheets and all other important information such as barge manifest
– Obtain Customs clearances and Marine Warranty Surveyor approval for the sailaway.
SURVEY REQUIREMENT
Prior to the barge arriving in field, a pre-installation survey will be conducted along the pipeline route to ensure that the corridor is clear of any recently deposited debrisor obstructions. This survey is in addition to any engineering or route selection surveys previously done, and will concentrate mainly on seabed surface features. This survey is normally done using towed side scan sonar techniques.
Any debris found during this survey will be reported to the Client, and suitable remedial works then conducted as agreed. This may involve the removal of the debris identified, or the pipeline route re-worked as appropriate. Additional work scope for the survey may also include the location cable and pipeline crossings, specific surveys at the edges of the pipeline corridor for anchor positioning, etc.
MOORING PROCEDURE
Details required for barge mooring and anchor handling can be found here. Details required for barge mooring and anchor handling can be found in structure Installation. During pipe lay operations, the barge will be moved ahead along the pipeline route on anchors. As the barge gets closer to the bow anchors, the anchors will be re-run. Similarly, the stern anchors will be moved closer to the barge as the pipelay progresses. These anchor moves will be done in turn regularly to ensure that the pipeline progress is not impeded.
DP PROCEDURE
More and more vessel uses DP these days for offshore construction sector. This is due to the congested seabed
PIPE LAYING
A) GENERAL
The following section addresses the steps to be taken for the installation of a typical pipeline, starting from the time the barge arrives in field to the time the pipeline is laid down at the other end. Pipelines are installed from a lay barge, which moves ahead under the stationary pipeline as individual pipe joints are welded together on-board. A conventional single joint S-lay system is described where the pipeline is supported by a stinger structure at the stern of the barge as it enters the water. The pipeline adopts a ‘S’ shape as it goes through an overbend at the stinger and then a sagbend near the seabed. Each pipe joint is normally delivered in 12 meter (40 feet)
In the conventional S-lay method, pipe joints are aligned and welded together on the barge pipe ramp. Each joint of pipe is aligned to the preceding joint using a hydraulic line-up station and an internal line up clamp. External line up clamps may be used for smaller diameter pipe (2-4’’), or as a backup for the internal clamps as necessary. After each joint is positioned in the first station of the pipe ramp, the first welding passes will be deposited. The barge is then pulled ahead, and the lineup process repeated for the next joint of pipe. The previous partially welded joint will be pulled into the next station in the ramp, where additional weld passes will be placed. This will continue until all the weld passes are completed, and will typically require 4 to 5 welding stations to finish, depending on the wall thickness of the pipe and the welding system used. When welding is complete, the joint will be NDT inspected. This can be done by radiographic inspection, using a gamma source or x-ray tube mounted on a motorized trolley or crawler inside the pipeline, or by ultrasonic testing, using external automatic equipment. External gamma or x-ray radiography may also be used on smaller diameter pipelines. Should an unacceptable defect be found, the pipelay process will cease while the defect is gouged out and re-welded. Upon a satisfactory inspection of the repair weld, pipelay will recommence.
Following NDT acceptance, the pipeline will be pulled down one more station to allow the application of a corrosion protection coating, and then the field joint in-fill. The pipeline then exits the stern of the barge, supported by a stinger into the water. The stinger supports the pipeline through an over bend as the pipeline drops off towards the seabed. The barge is pulled along the design route from under the pipeline as welding is completed. Tension is maintained on the pipeline using in-line tensioner units built into the pipe ramp. This tension determines the length and profiles of the over-bend and sag-bend portions of the pipeline as it falls to the seabed. The pipelay tension is engineered according to the characteristics of the pipe, the barge and stinger used and the water depth.
B) INTERNAL EQUIPMENT (INSIDE PIPELINE)
Some internal equipment used in the pipelay process is as described following. Most of this equipment is towed on a cable placed inside the pipeline. As the barge pulls ahead, the equipment remains stationary inside the pipe. An air tugger will then be used to pull the equipment up a joint upon the completion of the pull.
i) BUCKLE DETECTOR
This device consists of a wheeled body on which a ¼” thick circular steel plate is installed. The plate is sized to fit a percentage of the pipe ID. The percentage can be calculated using the DNV 1981 – Rules for Submarine Pipeline System. The buckle detector is ideally located two joints past the touchdown of the pipe on the seabed. The purpose of the device is to provide an indication of any anomalies in the pipeline ID after touchdown. The air tugger that pulls the internal equipment is equipped with a load cell and abnormal loads observed should be investigated by recovering the buckle detector.
ii) STOP TROLLEY
This device consists of a small, wheeled trolley that is attached to the cable inside the pipeline. The stop trolley’s function is to prevent the internal x-ray crawler from running past the stern of the barge and falling to the seabed inside the pipeline should there be any malfunctions. The trolley is attached to the cable near the stern of the barge to allow access to all the stations where welding or repairs will be done on the pipe ramp to the x-ray crawler.
iii) COPPER TUBING SHEATH
Copper tubing sections may be installed on the cable at the welding or repair stations where there is a possibility that the welding arc will penetrate to the ID of the pipeline. The copper tubing is installed in 4” long sections to preserve the flexibility of the cable, and serve to protect the cable from being damaged by the welding process.
iv) INTERNAL X-RAY CRAWLER
This is a battery operated, motorized trolley that houses the x-ray tube or gamma source. The trolley is remotely controlled from the outside of the pipeline to accurately position it to radiograph the required joint. The trolley straddles the internal cable.
v) INTERNAL CABLE
This cable is normally made up in two sections. The longest section is the stern most, connecting the buckle detector to the stop trolley. The second section is the partially copper sheathed section that connects the stop trolley to the back of the internal line-up clamp.
– Buckle detector cables must be IWRC cable of a minimum ½ inch diameter.
– Stop trolley cables should be a minimum ½” diameter and of IWRC construction except in smaller pipelines (8” / 6”) where the X-ray crawler clearance may mandate cables as small as ¼”. Great care to be exercised when smaller cables must be used.
vi) INTERNAL LINE-UP CLAMP
The internal line up clamp is a pneumatically operated device that locks two ends of pipe together for the initial welding passes. The clamp has two sets of radial dogs that engage individually on each end. The stern set is engaged on the pipeline end first to lock the clamp in place. The new joint of pipe is then introduced and lined up to the end of the pipeline. The forward set of dogs is then engaged, locking the two ends together. The final fit up alignment is then done before welding commences. Some internal clamps are fitted with copper backing shoes to accommodate automatic welding systems, while some automatic welding systems have welding bugs installed on the clamp itself to perform an internal root.
vii) REACH ROD
The reach rod is connected to the front of the line up clamp, and is used to release the clamp when welding at the first station is completed. The handle of the reach rod will stick out from the end of the joint of pipe in the line up station. The release of the clamp is done by rotating the reach rod handle.
C) WELDING SYSTEMS
The welding systems used for pipeline welding can be placed into 2 general categories, manual and automatic. Within the automatic family, further distinction can be made between the semi-automatic and the fully automatic variety. These areas described following.
i) MANUAL WELDING
This is the traditional method, and utilises a Shielded Metal Arc Welding or Stick (SMAW) process to gradually deposit all the weld material. A minimum of two welders are used, one on each side of the pipeline. On larger diameter pipe, four welders may also be used to expedite the welding.
ii) SEMI-AUTOMATIC WELDING
This method normally utilizes a bug-and-band system, where a tracking band is installed on each joint to be welded. Two welding bugs are then placed on the band, one on each side of the pipe. Each bug will typically have one or two welding torches on it, which will deposit weld metal to the joint as the bug travels along the band. The bugs and band are removed from the pipe when welding is completed at each station. The linear movement of the bug on the band and the oscillation of the welding torch on the bug about the centre of the weld are controlled electromechanically to regulate the rate of weld metal deposition. The alignment of the welding torch on the bug along the centre of the weld however requires welder control. The welding process is normally GMAW.
iii) FULLY AUTOMATIC WELDING
This method is normally deployed in framed systems, where the welding equipment is mounted on a semi-fixed frame straddling the pipeline at each station. As each joint comes to a stop at a welding station, the welding frame is placed on the pipeline, with the welding equipment central over the joint to be welded. A tracking device is then deployed from the frame to map the centre of the weld. The welding process then begins, with the welding torches following the mapped track. Welder intervention is still possible, but seldom required. The welding process is normally GMAW.
Note: The use of semi-automatic and fully automatic welding processes required correctly specified linepipe if they are to be used with optimum efficiency. Pipeline parameters such as length, diameter, wall thickness and straightness must be within the required tolerances. The cutback of corrosion and weight coatings must also be subject to tolerance control as specified in the AWS Specification. Welding engineer will be able to advise more on the welding systems.
D) PIPELINE START-UP
There are several ways of the pipeline to be start-up prior it being laid.
i) BEACH PULL START-UP
A beach pull start-up will normally involve the lay barge being set up in close proximity to the shore at the land fall location. A cable is deployed between the barge and the shore to pull the pipeline to the beach as it is welded on the barge. For short pulls (<600m), a stern anchor cable may be pulled to the shore, and then returned to the barge, via a suitably anchored snatch block at the beach. For longer pulls, a linear pull winch anchored at the beach, with the required length of cable on a spooler, will be used.
This pull cable is connected to the end of the pipeline on the barge. As successive joints of pipe are welded on the barge, the cable will pull the pipeline towards the shore, while the barge remains stationary. Alternate methods of performing a beach crossing start up exist, and these may include the welding of the pipe string onshore, the pre-laying of a string offshore, etc. Pipeline beach crossings are normally buried to protect the pipeline from the surf. The pipeline route is pre-trenched at the beach crossing location. The pipeline is then pulled to the shore in the trench, and later buried. The trench at the surf zone is normally protected during the construction and pipelay using a sheet piled cofferdam.
Some considerations for beach crossing works are as follows
- Pull force available is sufficient.
The pull force required is proportional to the submerged weight of the pipeline. The use of supplemental buoyancy on the pipeline should be considered to reduce the pull forces anticipated. A good rule of thumb is to reduce the submerged weight of the pipeline to where it is just negatively buoyant.
- Submerged weight of the pipeline is sufficient for stability following installation
In most cases, the installation requirements are at odds with stability requirements. The pipeline stability criteria may require an increase the pipeline’s submerged weight to the point where the pull force available for the beach pull is not sufficient. Buoyancy should then be used to reduce the submerged weight of the pipeline for the beach pull, but removed as soon as possible to ensure that the pipeline is not compromised.
ii) OFFSHORE PIPELINE START-UP
Some common methods of pipeline start-ups offshore are as follows.
- Bowstring or Elevated Hold Back Cable Jacket Start-Up
This method is used where a pipeline is started up from an existing jacket. A length of cable, the bowstring, is installed between two vertical points on a jacket. Another length of cable is attached to the bowstring on a running shackle, this connects the bowstring to the pipeline pulling head. The barge then lays away from the jacket, using the bow string as a reaction for the required pipeline tension.
Some variations to this method include the following:
– Attachment of the bow string on a horizontal plane, with fixed lengths of cable on each end of the bow string to dictate the final horizontal location of the pulling head on the seabed. Bow strings can sometimes be more time consuming to attach to the jacket but have the advantage of allowing easy connection to the pipeline without the use of stinger ballast.
– The use of weak links and load indicators on the pipeline start up cable to determine the maximum loads on the jacket, etc. This requirement may be mandated by Customers concerned with the ability of the platform to withstand start up tension loads. Where permitted by the customer the size of the start-up cable should be a minimum of 2” to obviate any chance of breaking the start-up cable and buckling the pipeline during start up. Upon the completion of pipelay, the barge will return to the start-up location to disconnect the pipeline from the bowstring. The pipeline is then lowered to the seabed, and made ready for the installation of a riser or connecting spool piece.
- Dead Man Anchor Start-Up
Dead man anchor start-ups are done where it is not possible to connect the pipeline pulling head to any existing structure. This may be typical when starting up at new complexes where the jackets are not yet installed. An anchor with a pennant buoy and a suitable length of start-up cable, with overlength, is first deployed by a tugboat or the vessel itself (if DP operated). The end of the start-up cable is then passed to the barge, where tension will be applied in the direction of pipelay, and a load test (also known s soka test) performed to ensure that the anchor is securely embedded. At this time, the length of the start-up cable is also checked and, based on the location of the barge, cut to length. This will ensure that the end of the pipeline ends up at the design location on the seabed. Following completion of the pipelay, the barge will return to the anchor location to retrieve the anchor and perform the required tie-in. The anchor may also be retrieved by a tugboat after a sufficient amount of pipe has been laid.
E) PIPELAY SEQUENCE
Following is a step by step account of the pipelay activity on a typical lay barge after the pipeline has been start-up (Section D)
Step 1: Deck Stock Pile
To ensure that there is a ready supply of line pipe, some joints may be stockpiled on the deck of the barge. These joints are used when the pipe haul barges are being changed out, or when bad weather precludes having a pipe haul barge alongside
Step 2: Longitudinal Conveyor / Line Pipe Swabbing / Bevel End Preparation
Line pipes are lifted from the pipe haul barge, or the deck stockpile, into a deck longitudinal conveyor for transfer into the ready rack. On some barges, there will be facilities for beveling the ends of the pipeline where the factory bevel is to be altered. This is normally done to suit an automatic welding system. A swabbing rabbit may also be run through the pipe as each joint is being transferred through this conveyor. This serves to clean mill scale or other dirt and debris from the internal surface of the pipe.
Step 3: Pipe Ready Rack / Bevel End Preparation / Pre-heat
The pipe ready rack transfers line pipe horizontally from the longitudinal conveyor into the pipe ramp. Further end preparation may be done here. The bevels on the line pipe will be pre-heated for welding, pipe tally numbers are recorded and joint numbers marked.
Step 4: Station 1 – Line up and Root / Hot Pass Welding
The first station of the pipe ramp will have hydraulically operated rollers, which align the next pipe joint to the end of the pipeline in the pipe ramp. The pipe will also be spun to allow the proper alignment of the longitudinal seam, if any. If an internal line up clamp is used, this will be set at the end of the pipeline. The next pipe joint is brought in to butt up with the pipeline, and the clamp set on the new joint. This will lock the two pipe ends together for the final fit-up and welding. When the fit up is acceptable, welding will commence on the joint. On most SMAW (stick weld) operations, this will consist of a root pass and a hot pass. This may vary with automatic systems. On larger diameter pipes and depending on the welding procedure used, the internal clamp may be released following the completion of the root pass and pushed into the pipeline. This allows access for a back welder to crawl or trolley down the open end of the pipeline to inspect the root pass of the weld internally. Some touch up welding may also be done. When the initial weld passes are completed, and the back welder has exited the pipeline, the barge will pull ahead. The internal equipment will remain stationary inside the pipe. At the end of the pull, the internal clamp will be at the second station of the pipe ramp, while the end of the reach rod is at the first welding station. When the next piece of pipe is rolled into the pipe tunnel, the cable from an air tugger will have been passed through the joint. The cable is connected to the end of the reach rod, and the internal cable then pulled up the pipeline to place the internal clamp at the first welding station again to repeat the cycle.
Step 5: Station 2 to 5 – Completion of Welding
Stations 2 to 5 are normally used to sequentially complete the butt weld on each joint. The welding passes required are divided between each available station, and optimized such that each pipe joint will spend the minimal time in each station before the barge is moved ahead.
Step 6: Station 6 – Visual Inspection, NDT
In Station 6, the cap weld will have been completed and the joint is now buffed and cleaned for visual inspection.
Step 7: Station 7 – NDT, Repair
Station 7 is normally lead or concrete shielded against radiation. Here, a strip of xray sensitive film will be wrapped around the weld, and exposed to radiation (RT) from the x-ray (or gamma ray in certain circumstances) crawler inside the pipeline. The exposed film is then passed to the adjacent processing laboratory and interpreted. Should an unacceptable defect be found, pipelay will be interrupted to allow a repair to be made and additional NDT done following. Automatic Ultrasonic testing where joints are subjected to inspection through automatic UT scanning of the weld is gaining increasing acceptance. This method gives a three dimensional picture (as opposed to 2D for RT inspection) of the weld defect and is sometimes used in conjunction with ECA (Engineering Critical Assessment) acceptance criteria.
Step 8: Station 8 – Field Joint Wrapping
If the weld is satisfactory, the exposed steel at the ends of the pipe will have corrosion protection applied in Station 7. This normally consists of a self-adhesive tape wrapped with sufficient overlap on itself and the parent corrosion coat on the line pipe although powder sprayed FBE may be used in some cases.
Step 9: Station 9 – Field Joint Infill
Where a concrete weight coat is specified, the cut back area at the end of each joint of pipe will need to be filled in. This provides continuity to the outside profile of the pipeline, and prevents interference between the cut back ‘notch’ and the stinger rollers. The infill material can be hot marine asphalt mastic or two part polyurethane foam. In either case, a mould of sheet metal or other suitable material will be installed and the fill material poured into the void. As most infill material used is quick hardening, the joint is then completed, and ready to be pulled into the stinger.
Step 10: Stinger
Stingers can be in the form of single section trusses or multiple section articulated types. Rollers are installed inside the stinger frame to support the pipeline. On truss stingers, these are set as engineered to provide the required radius of the overbend. Additional ballasting will be performed to place the depth of the stinger tip at the required depth. Articulated stingers have fixed rollers, and the sections are individually ballasted to provide the profile required. The end of a single section truss stinger or each section of an articulated stinger will be fitted with a pneumo hose installed for depth monitoring. Diver and / or ROV checks must also be performed regularly to ensure that there are no anomalies, and to observe that the pipeline is riding properly on the required rollers. Customer specifications in some cases require an underwater camera at the last roller of the stinger to observe the pipeline as it exits the stinger. Some will also require a load cell at the last roller to monitor roller reaction forces and confirm engineering calculations.
F) ABANDONMENT & RECOVERY (A&R)
A pipeline will be abandoned, or placed on the seabed upon the completion of the pipeline, or should inclement weather or other circumstances dictate that pipelay cannot proceed. Pipeline abandonment begins with the retrieval of all the internal equipment inside the pipeline, and the installation of a pulling head to the pipeline. The pulling head will be connected to the cable from the lay down winch located at the bow of the barge. When all is secured, the lay down winch will gradually take up the pipeline tension, and the tension machines released. The barge is then moved ahead, allowing the laydown winch to pay out under constant tension control. This will continue as the pulling head lays past the stern of the barge and the stinger. The distance that the barge needs to move ahead is engineered. When this distance is reached, the laydown winch tension may be released, allowing the pipeline to rest safely on the seabed. If the pipeline is completed, then a diver or the ROV will be sent to the pulling head to disconnect or cut the laydown cable. If the pipeline is to be abandoned temporarily, the cable may be left attached while the barge rides out the inclement weather. Pipeline recovery is done in reverse to the abandonment process. The barge is first set up over the pulling head, along the same heading as the pipeline. The laydown cable is then attached and the barge moved ahead a required distance. This is engineered, and is normally the same as the distance specified for abandonment.
The required tension is applied to the laydown cable, and the barge slowly moved astern. As the barge moves, the end of the pipeline will start to lift off the seabed, eventually entering the pipe ramp through the stinger. When the pipeline goes past the tension machines in the pipe ramp, the machines will be engaged. The load from the laydown winch is then gradually transferred to the tension machines.
The pulling head is then removed, the pipeline internal equipment re-inserted and pipelay recommenced. Both abandonment and recovery processes are sensitive procedures, and the ROV or divers should be employed to closely monitor the pulling head as it exits or enters the stinger.
PIPELINE CROSSINGS
A) GENERAL
New pipelines entering existing fields occasionally need to cross other existing pipelines or cables. The owners of these existing facilities normally specify that a certain amount of separation be maintained between the new pipeline and the existing pipeline or cable for damage prevention. Several methods exist in ensuring that this separation is met:
i) POST-INSTALLED CROSSING SUPPORTS
Some Clients may allow the laying of a new pipeline directly over an existing one, with the condition that the new pipeline be lifted and supported clear of the existing one later. In these cases, the barge will return to the site of the crossing following the completion of pipelay, lift the new pipeline, and then install supports under the new pipeline.
ii) PRE-INSTALLED CROSSING SUPPORT
As opposed to the previous case, the supports for the new pipeline are pre-installed prior to the new pipeline being laid across the existing pipeline or cable. This may be done in advance of the pipelay, or during pipelay itself. In the former case, a survey-equipped workboat will be deployed to lower the required supports on the pipeline route. In the latter, pipelay will be suspended when the barge is directly over the support location. The supports are then lowered to the seabed using the barge crane. At this time, the pipeline touch down will be some distance astern of the support location.
B) CROSSING SUPPORT CONFIGURATIONS
Available support material includes the following:
- Bitumen mattresses – a handling frame is required to deploy these.
- Concrete mattresses – a handling frame is required to deploy these.
- Concrete slab structures.
- Composite Steel / Concrete structures – these are normally specially designed for the job at hand.
- Grout bags – these are normally used for the post-installation crossing case. Crossings over existing pipelines normally consist of a central support close to the existing pipeline, with auxiliary supports either side to check excessive free spanning. Crossings over buried cables normally consist of an equal number of supports either side of the cable crossed. The central span of the new pipeline where the crossing occurs is normally near the extremity of the allowable free span length.
FREE SPAN CROSSING CORRECTION
A) GENERAL
Freespans occur when the pipeline is laid over undulating or pockmarked seabed terrain. The acceptable lengths of the freespan for each pipeline are dependent upon the physical characteristics of the linepipe, as well as the on-bottom current conditions. Allowable free spans in the pre-flood, post flood, hydrotest and operating pipeline conditions are advised by the pipeline designer prior to commencement of installation operations. These free spans are detected during the post-lay survey usually using analogue side scan sonar equipment. Digital multibeam echosounders or “Swath” equipment is also used in conjunction with free span surveys. In some cases the nature of the seabed may mandate the installation of prelay berms (rock supports) prior to commencement of pipelay operations.
B) FREE SPAN CORRECTION METHODS
Common methods used to correct free spans include:
i) Jetting – This is done using a jetting machine to lower the pipeline at the high point supports on the seabed. This is a commonly used when a new pipeline is laid in areas with sand wave activity.
ii) Grout Bagging – This is done by installing grout bag supports underneath the pipelines to reduce the unsupported lengths. Grout bag installation is normally done using divers, although technology now also exists for ROV installed bags.
RISER/SPOOL PIECE INSTALLATION
A) GENERAL
Subsea pipelines are connected to offshore platforms via riser pipes that go from the seabed to the topside deck. Depending on the design of the platform, some risers are pre-installed on the jacket, with a flanged spool piece connecting the pipeline to the riser. The majority of other risers are welded to the end of the pipeline on the surface and then lowered into clamps installed on the outside face of the jacket.
B) SPOOL PIECE TIE-INS
Spool piece tie-ins are performed where the pipeline is laid down close to a jacket with a preinstalled riser. A connecting piece of pipe – the spool piece – is then fabricated based on the measurements taken between the respective pipeline and riser flanges, and installed. The spool piece may involve bends to fit the geometry of the pipeline route near the jacket as well as to accommodate any expansion due to the heat of the pipeline product. Spool pieces may also be used to join the new pipeline to a PLEM or other subsea structure. The installation methodology as discussed will remain essentially similar. The subsea flanges used are normally of the ring joint variety, and the bolted connections are torqued mechanically to ensure that the seal is uniform. Some important considerations when executing these tie-ins are as follows:
- The pipeline end will be exposed during the tie-in, this will normally involve either flooding the entire pipeline before removing the laydown head or installing a sealing plug.
- The geometry of the pipeline route relative to the riser end is important in order to have the flanges parallel when mating up. Consideration should be given to altering the route of the pipeline near the jacket lay down location to suit the as-built jacket orientation. In congested complexes use of a sector scan should be considered to assist in obtaining an overall picture of relative positions / orientations etc.
- Proper distance and angle measurements are to be taken between the pipeline and riser flanges. This will ensure that the spool piece is correctly fabricated. Redundant measurements should be taken for confirmation.
When the diver has made the measurements, it will be the duty of the Field Engineer to calculate the required lengths of each straight portion of the spool piece for fabrication. When the fabrication is completed, the spool piece will be lowered to the seabed for installation.
C) WELDED RISERS
When the Client specifications do not allow a subsea flanged connection between the pipeline and the riser, the end of the pipeline will need to be lifted to the surface, and a riser welded on. The riser section normally comprises a horizontal section and a vertical section joined by a suitable bend. Expansion loop and offset sections may be required on the horizontal section in some cases.
The pipeline will be lifted from the seabed using davits installed at the side of the barge or in some instance single point lifted using the derrick crane. These lifting calculations must be carefully engineered beforehand. When the pipe tip is on the surface and secured, the pulling head will be removed and the end prepared for welding. An external ‘rough weather clamp’ or ‘bear clamp’ will be installed at the end of the pipeline. This is to provide a stabbing cone for the installation of the horizontal section of the riser, as well to serve as an external clamp for fitting up and welding. Some important considerations are as follows:
- The pipeline should be lifted and lowered once before the measurement is made. The first lift will serve to ‘exercise’ the pipeline, and when it is lowered, the end of the pipeline will be at its final, and repeatable, location.
- Proper distance and angle measurements are to be taken between the pipeline and jacket base. A mark should be made on the pipeline where the measurement is taken. Markers are sometimes placed on the bottom brace marking the location of the riser. This will ensure that the horizontal sections of the riser are correctly fabricated. Redundant measurements should be taken for confirmation.
- Proper measurement of the water depth at the base of the jacket should be done, or good as-built drawings of the jacket should be available to ensure that the length of the vertical riser section is correct and that field joints and anodes are clear of riser clamp locations.
- Proper attention is to be paid to the rigging for the riser vertical-section to ensure that the stab-in can be made easily, and the riser sections not overstressed at any time. Non-determinate lift arrangements are often required.
C) DAVIT LIFTING
Davit lifting of pipelines involves the connection of a series of pipeline davits to the pipeline subsea, and then gradually / sequentially hoisting on individual davits to lift the end of the pipeline to the surface. The davits serve not only to provide an upward lift force on the pipeline, but also a tension component axially in the pipeline. Two major families of davit lifts exist:
i) MULTIPLE DAVIT LIFT
In this configuration, three or more davits will be attached to the pipeline. The spacing of the davits on the deck of the barge and the attachment points on the pipeline are engineered, and the lift sequence is worked out to ensure that the pipeline is not overstressed. The davit attachments near the pulling head end will provide higher vertical lift components, while the larger lead angles on the pipeline end attachments provide axial components to place the pipeline in tension.
ii) SINGLE POINT LIFTS
In this case the Derrick crane is attached to a single point on the pipeline and having established the correct lead angle lifts the pipeline in one continuous operation. Care to be taken with the attachment point to the pipeline as outlined below.
Considerations to be kept in mind when planning davit lifts include:
- Pre-installation of lifting chokers on the pipeline at the surface, as the pipeline is being laid down. Each davit connection point should comprise two double wrapped chokers, a connecting sling and a running shackle to maximise the effective distribution of load. On concrete coated pipes Chokers should be connected leaving the maximum length of concrete between the connection point and the field joint in the direction of pull to keep to a minimum the chance of concrete slippage during lifting.
- The position and heading of the barge over the pipeline at the start of the davit lifting operations is crucial to ensure that the lead angles on the davit cables are per design.
- Pneumo lines should be attached to all the davit attachment points on the pipeline to enable profile monitoring. Where the davits may not have cable pay out counters or load cells, this will prove to be the best guide to keeping the lift sequence. Electronic beacons that attach to davit blocks are a recent innovation that are available as a substitute for pneumos.
- Where a welded tie-in is to be made, the davit lift should be engineered such that the pipe tip is no more than 20° from horizontal at the final stage. This allows the riser section to be easily stabbed into the end of the pipeline, as well as providing easier access for welding and NDT.
- The pipeline should be adequately secured when on the surface against excessive lateral movement. This can be done using additional safety slings, which will also secure the pipeline in case of a davit failure.
AS-BUILT SURVEY INFORMATION
Typical as-built survey information required for pipeline installations are as follows:
– As-laid position of the pipeline as obtained by side scan sonar.
– Optional as-laid condition of the pipeline as obtained by ROV video.
– Determination of span lengths and heights by ROV and /or side scan sonar.
– Details of rectification work done on spans, normally by ROV video.
– Details of pipeline or cable crossings, normally by ROV video.
The presentation of this data will normally be consolidated into large-scale alignment sheets
Source: J. RAY McDERMOTT, S.A.EASTERN HEMISPHERE