Pipelines and Risers

Pipelines and Risers, Volume 3
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Oil price and discount rate sensitive. Useful for: ranking project viability, decommissioning overviews, infrastructure EPIC Capex overview. Infield Reports provides an easily accessible sector-specific overview, highlighting key themes, regional capex trends and companies active within the market over a ten year historical and forecast timeframe. Online business intelligence dashboard which increases the analytical value of our reports and trackers by delivering them via an interactive system that dynamically updates its views based on user choices.

The pipelines data set identifies projects ranging from the intercontinental export lines through to the infield flowlines and export lines down to 1" diameter and 1 metre in length jumper flowlines connecting a templated well to its template. By there were 11 pipelines serving the allies. It was not until , however, that the first pipeline was laid to connect an out of sight of land offshore field development. There are over 45, pipelines on the Offshore Energy Database, some of which are not expected to be installed until To give you the best possible experience, this site uses cookies.

By browsing our site and viewing its content you consent to use cookies. Click here for more information. If the water depth is relatively deep, the floating structures moored by tendons or chains are recommended see Figure 1.

Fixed platforms, steel jacket or concrete gravity platform, are installed in up to 1, ft water depth Shell Bullwinkle. Four 4 compliant piled towers CPTs have been installed worldwide in water depths 1, ft to 1, ft. It is known that the material and fabrication costs for CPT are lower but the design cost is higher than conventional fixed jacket platform. Total 16 spars, including 15 in GOM, have been installed worldwide in water depths 1, ft to 5, ft Dominions Devils Tower.


Floating production storage and offloading FPSO has advantages for moderate environment with no local markets for the product, no pipeline infra areas, and short life fields. Floating structure types should be selected based on water depth, metocean data, topside equipment requirements, fabrication schedule, and work-over frequencies. Table 1. Subsea tieback means that the production lines are connected to the existing subsea or surface facilities, without building a new surface structure.

Due to space and weight limit on the platform deck, topside processing facility is required to be compact, so its design is more complicated than that of an onshore process facility. Requirements on topside processing systems depend on well conditions and future extension plan. General topside processing systems required for typical deepwater field developments are: Well control unit Hydraulic power unit HPU Uninterruptible power supply UPS Control valves Multiphase meter Umbilical termination panel Crude oil separation Emulsion breaking Pumping and metering system Heat exchanger crude to crude and gas Electric heater Gas compression Condensate stabilization unit Subsea chemical injection package Pigging launcher and receiver Pigging pump, etc.

The APD requires detailed information about the drilling program for evaluation with respect to operational safety and pollution prevention measures. Other information including project layout, design criteria for well control and casing, specifications for blowout preventors, and a mud program is required.

The developer must design, fabricate, install, use, inspect, and maintain all platforms and structures to assure their structural integrity for the safe conduct of operations at specific locations. Factors such as waves, wind, currents, tides, temperature, and the potential for marine growth on the structure are to be considered. All surface production facilities including separators, treaters, compressors, and headers must be designed, installed, and maintained to assure the safety and protection of the human, marine, and coastal environments.

The DOT is responsible for regulating the safety of interstate commerce of natural gas, liquefied natural gas LNG , and hazardous liquids by pipeline. The DOT is responsible for all transportation pipelines beginning downstream of the point at which operating responsibility transfers from a producing operator to a transporting operator.

The DOIs responsibility extends upstream from the transfer point described above. The MMS is responsible for regulatory oversight of the design, installation, and maintenance of OCS oil and gas pipelines flowlines. Routes are also evaluated for potential impacts on archaeological resources and biological communities. The design of the proposed pipeline is evaluated for: Appropriate cathodic protection system to protect the pipeline from leaks resulting from the external corrosion of the pipe; External pipeline coating system to prolong the service life of the pipeline; Measures to protect the inside of the pipeline from the detrimental effects, if any, of the fluids being transported; Pipeline on-bottom stability that is, that the pipeline will remain in place on the seafloor and not float ; Proposed operating pressures; Adequate provisions to protect other pipelines the proposed route crosses over; and Compliance with all applicable regulations.

If the MMS determines that the pipeline may constitute a hazard to other uses, all pipelines regardless of pipe size installed in water depths less than ft must be buried. The purpose of these requirements is to reduce the movement of pipelines by high currents and storms, to protect the pipeline from the external damage that could result from anchors and fishing gear, to reduce the risk of fishing gear becoming snagged, and to minimize interference with the operations of other users of the OCS.

Any pipeline crossing a fairway or anchorage in federal waters must be buried to a minimum depth of 10 ft below mudline across a fairway and a minimum depth of 16 ft below mudline across an anchorage area. Obstructions, debris, existing pipelines or structures Environmentally sensitive areas beach, oyster field, etc.


Joseph Peter. Love Kushwah. Figure 3. The soil data is very important to estimate the pipeline on-bottom stability. PIP system requires bulkheads, water stops, and centralizers, depending on fabrication methods. In Level 2 analysis, it is noted that the vertical safety factor in the output should be treated as a reference use only.

If the pipeline-soil friction resistance is too small, the pipeline will spring-back to straight line. The formula also can be used to estimate the required minimum straight pipeline length L s , before making a curve, to prevent slippage at initiation. If L s is too short, the pipeline will slip while the curve is being made. R s L s Lay direction Initiation point - Bathymetry hydrographic survey using echo sounders provides water depths sea bottom profile over the pipeline route.

The new technology of 3-D bathymetry map shows the sea bottom configuration more clearly than the 2-D bathymetry map see Figure 3. Figure 3. It uses narrow beams of acoustic energy sound which is transmitted out to the seabed topography or objects within the water column and reflected back to the towfish. It is used to identify obstructions, outcrops, faults, debris, pockmarks, gas vents, anchor scars, pipelines, etc. Typically objects larger than 1m are accurately located and measured see Figure 3. It is near-bottom towed by a cable from a survey vessel. The soil sampling instruments include grabs, gravity drop corers, and vibracorers.

Drop corer or gravity corer is a device which is dropped off from a survey vessel. And on contact with the seabed, a piston in the device is activated and takes a shallow core up to a meter or so in depth. This core is retained and preserved in the device and then hauled back to the surface. The core samples collected are photographed, logged, tested by either Torvane or mini cone penetrometer and sampled onboard the survey vessel. Further sampling and geotechnical testing can be undertaken in the laboratory. The cone penetration test CPT provides tip resistance, sleeve friction, friction ratio, undrained shear strength, and relative density.

Figures 3. Bonnel, et. Conceptual study Pre-FEED defines technical feasibility, system constraints, required information for design and construction, rough schedule and cost estimate Preliminary design FEED defines pipe size and grade to order pipes and prepares permit applications. Detail engineering defines detail technical input to prepare procurement and construction tendering.

The pipeline design procedures may vary depending on the design phases above. Tables 4.

Related Publications

Design basis is an on-going document to be updated as needed as the project proceeds, especially in conceptual and preliminary design phases. Fluid property sweet or sour - Table 4. As the pipe size increases, the arrival pressure and temperature decrease. Then, the fluid may not reach the destination and hydrate, wax, and asphaltene may be formed in the flowline. If the pipe size is too small, the arrival pressure and temperature may be too high and resultantly a thick wall pipe may be required and a large thermal expansion is expected.

If the flowline is to transport a sour fluid containing H2S, CO2, etc. Alternatively, a corrosion allowance can be added to the required pipe wall thickness. Figure 5. The blue solid line represents inlet pressure at wellhead and the red dotted line represents outlet fluid temperature.

Introduction to Offshore Pipelines & Risers - Jaeyoung Lee

The 8 ID pipe may require a heavy thick wall and the 12 ID pipe may require a thick insulation coating depending on hydrate wax or asphaltene formation temperature. From flow assurance analysis, the type, quantity, and size of each umbilical tube are determined. Most commonly used chemicals are; scale inhibitor, hydrate inhibitor, paraffin inhibitor, asphaltene inhibitor, corrosion inhibitor, etc. The umbilical terminates at subsea umbilical termination assembly SUTA and each function hose or cable connects to manifold or tree by flexible flying leads. Figure 6.

Unlike a bend stiffener, the bend restrictor does not increase the umbilical or pipes stiffness. When the bend restrictor is at "lock up" radius, it prevents the umbilical or pipe from over bending, kinking, or buckling. Bend restrictors can be manufactured from polyurethane or steel. The half shell elements are bolted together around the pipe and the next elements are bolted to interlock with those already in place. Each element allows to move a small angular distance and when this distance is projected over the length of the restrictor, the lock up radius is formed.

This radius is to be equal to or greater than the minimum bend radius of the flexible. Bending stiffeners are used at the termination point of cables, umbilicals, and flexible pipes where the stiffness of the system undergoes a step change. This sudden stiffness change between the flexible and rigid termination structure creates high levels of stress when the flexible is bent.

In a dynamic situation such as repeat bending, this can lead to fatigue failure in the flexible. Bend stiffeners are utilized to increase the stiffness of the flexible. The most common method of achieving this is to attach an molded elastomer tapered sleeve to the flexible. Medium or high carbon carbon content greater than 0. Carbon equivalent CE refers to method of measuring the maximum hardness and weldability of the steel based on chemical composition of the steel.

The CE shall not exceed 0. The yield strength is defined as the tensile stress when 0. The DNV code [2] defines the yield stress as the stress at which the total strain is 0. Figure 7.

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If the load exceeds the elastic limit, the pipe does not go back to its origin when the load is removed. Instead, the stress reduces the same rate slope as the elastic modulus and reaches a certain strain at zero stress, called a residual strain. It is most expensive but ideal for small diameter, deepwater, or dynamic applications. Currently up to 24 OD pipe can be fabricated by manufacturers.

The longitudinal seam is welded by double inside and outside submerged arc welding. ERW pipe is cheaper than seamless or DSAW pipe but it has not been widely adopted by offshore industry, especially for sour or high pressure gas service, due to its variable electrical contact and inadequate forging upset. Good for high fatigue areas such as riser touchdown region, stress joint, etc.

Subsea Pipelines and Risers

Applications can include casing, air can, and risers. Some key properties of each material are introduced in Table 7. Table 7. This pipe reduces material cost by using a thin wall CRA pipe at inner pipe wall surface to resist internal corrosion. And the carbon steel outer pipe wall provides structural integrity. Special caution should be addressed during clad pipe welding to the low carbon steel pipe, since hydrogen induced cracking HIC can occur by dissimilar material welding process.

However, its application is going to expand to subsea use due to its excellent corrosion resistant and low thermal expansion. Each layer is un-bonded and moves freely from each other. It is known for excellent dynamic behavior due to its flexibility. However, the flexible pipe size is limited by burst and collapse resistance capacities. The maximum design temperature is o C due to the plastic layers limit.

The maximum pipe size made by industries is 19 by year Flexible pipes manufacturing limit maximum design pressure is shown in Figure 7. For a sour service, a stainless steel carcass is required. For a water injection line, a smooth plastic bore can be used. The smooth bore is not normally used for gas applications due to gas permeation problem. The pressure build-up in the annulus of the pipe can occur due to diffusion of gas through the plastic sheaths. When no carcass is present, the inner plastic layer will collapse if the annulus pressure exceeds the bore pressure, such as shut-off case.

To avoid this problem, gas vent valves are installed at end fitting to relieve the annulus pressure. Rough bore with carcass can cause noise and vibrations at high flow velocity. Another key component of the flexible pipe is the end fitting Figure 7. To reduce the flexible pipe weight especially for dynamic riser use and improve corrosion resistance, a composite material, such as for tensile wires, has been developed.

The flexible hose is commonly used for topside jumpers, single point mooring SPM risers, and surface floating risers to offload the product from the buoy to FPSO or shuttle tanker see Figure 7. The built in one-piece end couplings with integral built in bend limiters and a composite fire resistant layer provide a low minimum bend radius, a light compact construction with excellent flexibility and fatigue resistance. However, there are some manufacturing limits on hose size and length; the maximum hose size is 30 and the maximum length is 35 ft.

Tubing diameter normally ranges from 0. The worlds longest continuously milled CT string is 32, ft. CTs yield strengths range from 55 ksi to ksi [8]. CT has been developed for well service and workover and expanded the applications to drilling and completion. The coiled tubing manufacturers include Quality Tubing, Inc. Kenawy and Wael F. Outer surface of the carbon steel line pipes are typically coated with corrosion resistant FBE or neoprene coating.

Thermally sprayed aluminum TSA coating can be used for risers especially when there is a concern on CP shielding due to strakes or fairings. The coating materials normal thickness and temperature limit are as follows: Fusion Bounded Epoxy, 0. The active heating methods include, electric heat tracing wires wrapped around the pipeline, circulating hot water through the annulus of pipe-in-pipe, etc.

The passive heating method is insulation coating, burial, covering, etc. Glass syntactic polyurethane GSPU , PU foam, and syntactic foam commonly are the commonly used subsea insulation materials see Figure 8. Although these insulation materials are covered jacketed with HDPE, they are compressed due to hydrostatic head and migrated by water as time passes, so it is called a wet insulation. Figure 8. Lower U value prvides higher insulation performance.

Heat loss can occur by three processes: conduction, convention, and radiation. Conduction is a heat transfer through a solid by contact, and convection is a heat transfer due to a moving fluid. Radiation is a heat exchange between two surfaces heat is radiated to the surrounding cooler surfaces.

Good insulation can be achieved by minimizing the above heat loss processes. Conduction is dependent on material size and thermal conductivity. Convective heat transfer film coefficient can be obtained from internal and external fluid Reynolds and Prandtl numbers. Best U value 0. The density is 0. Developed for the reeling process and many track records exist. Requires centralizers with a spacing of every 2m or so. PUF 2 nd cheapest form of insulation. Densities are in the range of 0. Use with reel-lay has been limited due to potential damage compression and crack during reeling.

Wacker is purchased by Porextherm. Most expensive thermal insulation product. Good U-value 0. Standard density is 0. Mineral Wool Cheapest form of insulation. Poorest U-value 0. Not good for low U value unless combined with other method such as heat tracing. PIP system requires bulkheads, water stops, and centralizers, depending on fabrication methods.

The end bulkhead is designed to connect the inner pipe to the outer pipe, at each pipeline termination see Figure 8. Intermediate bulkheads may require for reeled PIP to allow top tension to be transferred between the outer pipe and the inner pipe, at intervals of approximately 1 km. During installation, the tensioner holds the outer pipe only, so the inner pipe tends to fall down by its dead weight and may result in buckling at sag bend area near seabed, if no intermediate bulkheads exist. Considering low fabrication cost and low heat loss, it is recommended to install one or two water stops per each stalk length.

The stalk length varies, due to spool base size and pulling capacity, typically between m to 1, m. It should be noted that the water stops are not a design code requirement but they are recommended for deepwater project where recovery of the flooded pipeline is challenging. EPDM ethylene propylene diene monomer rubber, Viton a brand of synthetic rubber , and silicone rubber have been used for the water stop material. The axial compression for the water stops is provided by using an interlocking clamp arrangement which will provide the radial expansion of the ring against the pipe walls.

Centralizers or spacers see Figure 8. The annulus gap should be in the range of 30 to 40 mm and the net gap between insulation and outer pipe ID should be 15 mm or higher see Figure 8. The maximum reeled PIP that has been installed by Technip is One inch is the minimum concrete coating thickness that fabricator can put on. It should be evaluated if concrete coating is the most cost effective option to increase pipe weight. Increasing the pipe wall thickness may be more efficient considering pipe transportation and project management cost for the concrete weight coating.

Each pipe end is left without concrete coating for welding and welding inspection. No coating is applied near the pipe end for automatic welding and automatic ultrasonic test AUT , as indicated in Figure 8. The concrete coating stop distance from the pipe end is also called concrete cut-back length. Delafkaran and D. Design factor inverse of safety factor used for burst pressure check hoop stress varies due to the pipe application; oil or gas and pipeline or riser. The 0. This is because the riser is attached to a fixed or floating structure and the risers failure may damage the structure and cost human lives, unlike the pipeline failure.

Moreover, gas riser uses lower design factor than the oil riser, since gas is a compressed fluid so gas risers failure is more dangerous than the oil risers. Table 9. The empty pipe dry weight in air is Therefore, the pipe specific gravity is 1. The submerged pipe weight is The gas pipeline riser requires 0. For a deepwater application, the external hydrostatic pressure should be accounted for by using P instead of P. The above thin wall pipe formula assumes uniform hoop stress across the pipe wall and gives a conservative result high hoop stress.

However, the hoop stress is not uniform and it is maximum at inner surface and minimum at outer surface as shown in Figure 9. Normally the buckle propagation resistance requires heavier WT than the collapse resistance. However, if a buckle arrestor is installed at a certain interval typically a distance equivalent to the water depth , the buckle propagation is prevented or stopped arrested and no further damage to the pipeline beyond the buckle arrestor can occur.

In this way, we can save some pipe material and installation cost by designing the pipe for collapse resistance. If the buckle propagation pressure is higher than the differential pressure, buckle will not propagate travel. However, buckle will propagates if the calculated buckle propagation pressure is less than the differential pressure. Some contractors prefer thick wall pipe joint to buckle arrestor. Figure 9. As shown in Figure 9. If the calculated Von Mises stress falls inside of the curve, the pipe is considered safe in terms of combined resultant stress.

Boresi, Richard J. Schmidt, and Omar M. Shinley and Larry D. The thermal elongation is a function of the pipe materials thermal expansion coefficient , differential temperature T between the conveyed fluid temperature and the ambient temperature when the pipe is welded, and the pipeline length L. The thermal expansion analysis is not simple and FEA finite element analysis tools are commonly used to handle sea bottom irregularities, flowline route curvatures, and pressure and temperature variance along the route.

Snaking lateral displacement or upheaval buckling vertical displacement can occur due to excessive flowline enlogation when both ends are restrained and are not allowed to move freely. Figure Random buckle arrestors random rock dumping, burial, anchor, etc. At a certain point, the soil friction resistance equals or exceeds the flowline expansion load.

Beyond this point, called a virtual anchor point, the flowline will not move.


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The flowline walking can occur when the virtual anchor point moves between when flowline is warmed operation and when it is cooled down see Figure Repeated shutdowns and startups cycles may cause the axial walking and require anchor pile to hold back the flowline from walk-away.

Otherwise, a steel catenary riser SCR may buckle due to reduced sag bend radius at seabed due to accumulated pipeline walking. Colquhoun, et. Craig, et. Palmer, et.

Technology - Riser Systems

Bruschi, et. Hobbs and F. Most installation contractors require a minimum 1. After installation, before the pipe is filled with water or product fluid, the pipe should be checked for 1 year return period waves and current conditions. If the pipe is laid as empty for a long period before commissioning, a 2-year, 5-year, or year return period metocean data should be used. During operation, the pipe should be stable for a year return period metocean data. The soil data is very important to estimate the pipeline on-bottom stability.

The AGA pipeline on-bottom stability program [1] is widely used by industries. The program has three modules: Level 1 Simple and quick static analysis using a linear wave theory and Morison equations as above, without accounting for pipe movement or self- embedment. Level 2 - Reliable quasi-static analysis using a non-linear wave theory and numerous model test results considering pipes self-embedment.

Level 3 - Complicated dynamic time domain analysis using series of linear waves and allowing some pipeline movements. Compare the computed pipe stresses and deflections with allowable limits. Level 2 is recommended for most cases. Level 3 can be used to predict pipeline movements especially for dense sand or stiff clay where the pipe embedment does not take a big role. However, Level 3 takes a long computer running time and it is difficult to estimate how far the pipeline will move over the design life.

Therefore, Level 3 is not recommended unless small savings of concrete coating can affect the project cost significantly. In Level 2 analysis, it is noted that the vertical safety factor in the output should be treated as a reference use only. This is because the lift force is already considered in the horizontal stability check see Eq.

Once the pipe is lifted off the seabed, the water will start to flow underneath the pipe. The underneath flow velocity is faster than the upper flow, thus the underneath pressure is less than the upper pressure. This pressure differential tends to push the pipeline back to the seabed and drastically reduces the lift force. Ellinas, et. The best way is to avoid free spans but if not avoidable, it is necessary to check if the anticipated free span length is acceptable for static and dynamic loads.

The dynamic loads come from vortex induced vibration VIV, see Figure If the actual free span length exceeds the maximum allowable free span length, the free span should be corrected using one of the mitigation methods below also see Figure Sumer and J. Lee and D. Website, www. It is a natural tendency of a refined material steel to return to its original state iron ore. A corrosion resistance coating is applied to prevent corrosion, but a cathodic protection CP system using anodes is used as a supplemental corrosion protection system.

This is because the corrosion coating can be damaged during pipe transportation and installation. For the pipeline CP system, half shell anodes are tied-on the pipe outer surface at certain intervals. Typically 75 to lb aluminum alloy anodes are installed at to 1, ft intervals. Structural anodes can also be installed at PLET, to reduce offshore anode installation time and to keep the anode from being buried into the soil. For the case of installing the anodes on the PLET, attenuation calculation is needed to check if the anode current can flow to the designated distance.

There are four components in CP system see Figure The electrochemical potential, current capacity, and consumption rate of these alloys are superior for CP than iron. The driving force for CP current flow is the difference in electrochemical potential between anode and cathode.

Table A concrete mattress with integrated anodes embedded in concrete blocks has been developed to provide both pipeline stabilization and a local CP source. Most widely used installation method is using a pipeline installation vessel which can weld pipe joints on the deck and lower the pipes by releasing the pipes from the tensioners while moving the vessel.

Depending on the pipelines profile from the vessel to the sea floor, it is called S-lay or J-lay. Another installation method is to fabricate the pipeline at spool base near beach and reel the pipe onto the reel ship.


Then the reel ship carry the reeled pipe to the project field and lay by un-spooling the pipes. The four 4 pipeline installation methods are listed below and illustrated in Figure Details of each installation method are listed below. S-lay and J-lay configuration is shown in Figure There are multiple welding stations in S-lay, depending on pipe size and pipe WT. Therefore, it is important to control the time spending at each station. For example, if each station takes 7 minutes to connect one pipe joint 40 ft , the lay rate would be 1.

Pipe strain or curvature variance during reel-lay is presented in Figure The pipe strain is near zero when the pipe departs the stinger. The pipe is reeled on a spool at spooling base as shown in Figure The maximum reelable pipe size is 18 OD due to pipe strain and tension limit during reeling. The reeled pipe WT needs to be thick enough to avoid wrinkle see Section 9. Some deepwater installation vessels are shown in Figure As a reference, some dynamically positioned DP vessels which can lay pipes in water depth greater than 3, ft are listed in Table The installable water depth varies with pipe size and weight.

To determine whether the designed pipe can be installed by any installation vessel currently available in the industry, at least the normal installation analysis should be done before the pipe ordered. The installation vessels limit such as tensioner, stinger, etc. Several programs available for pipeline installation analysis are: Offpipe, Orcaflex, Flexcom, etc. The pipe stress limit during installation is not specified in any industry codes or standards.

At sagbend, the pipe is hard to control, like at stinger, so more stringent stress limit lower stress limit is applied. For the dynamic analysis, higher stress limits are used since more severe environment and vessel motion are considered. If strain criteria are used, a 0. Recovery follows the reversed order of the abandonment procedures. The SPL cable from a crane or davit on the vessel is free hanged vertically, at side of the vessel.