[Article Sharing] Horizontal and Vertical X-mast tree

Drivers influencing the evolution of horizontal and vertical trees | Exploration & Production Magazine

Source: http://www.epmag.com/drivers-influencing-evolution-horizontal-and-vertical-trees-698041#p=full

The capability and flexibility offered by modern subsea christmas trees and production systems is, by any measure, truly impressive. The industry has moved from simple production systems to more expansive ones incorporating complex controls and sensors and a range of monitoring and diagnostic systems.

This equipment operates in very challenging environments and stands as a testament to the skill and ingenuity of the teams that design, build, and install it.

The demands for the production of hydrocarbons from deep water at higher pressures and temperatures, coupled with a range of additional design constraints, ensure that subsea tree systems will continue to evolve to meet these challenges both now and in the future.

In the subsea industry much debate is generated comparing the relative merits of horizontal and vertical sub-sea tree systems. This article considers some of the primary drivers of this discussion and how they may influence both system design and future operations.

Horizontal and vertical trees

Subsea production trees can be segmented into two main types: horizontal trees and vertical trees. Horizontal trees are so called because the primary valves are arranged in a horizontal configuration, and likewise vertical trees have the primary valves arranged in a vertical configuration.

A key requirement of a subsea tree is that access is enabled to the “A” annulus between the production tubing and casing. This is required for a number of reasons, including pressure monitoring and gas lift. As an example, any pressure buildup in the A annulus can be bled to the production flowline via a crossover loop on the tree.

The original designs of subsea vertical trees and tubing hangers were of a dual-bore configuration. Prior to removal of the BOP, it is necessary to set plugs in both the production and annulus bores. Access to both bores requires the use of a dual-bore riser or landing string. The handling and operation of dual-bore systems compared to monobore systems is more complex, and time-consuming and, therefore, more costly.

On a horizontal tree, access to the A annulus is incorporated into the tree design and controlled by gate valves rather than plugs. This enables operations with a mono-bore, less-complex riser or landing string, which can deliver significant advantages, particularly in deep water. It is exactly this logic that led to the introduction of tubing-head spools for use with vertical trees, thereby offering many of the advantages of a horizontal tree.

Hangoff location

Another key functional difference relates to the hangoff location of the completion. In a vertical tree system the tubing hanger is landed either within the subsea wellhead or within a tubing-head spool. The subsea tree is then installed on top of the wellhead or tubing-head spool. In the case of the horizontal tree, the tree is installed on top of the subsea wellhead, and the tubing hanger is landed within the tree body.

This key difference means that, in the case of the horizontal tree, recovery of the completion can be achieved without removal of the tree. In the case of the vertical tree, access to recover the completion first requires removal of the tree itself. This functional variation is another input into the choice between horizontal and vertical trees.

If the probability of a failure in the completion (requiring its recovery) is higher than a failure in the tree (requiring recovery of the tree), then there may be a strong case for favoring a horizontal tree. The converse also is true; if a failure in the tree is considered the highest risk, then application of vertical tree technology incorporating the most efficient opportunity for its recovery may be favored over horizontal tree technology, where recovery of the tree first requires recovery of the completion.

The relative ease of recovery of tree or completion is then the key functional difference. The overall system choice is, in many ways, application-specific and dependent upon a large number of factors. However, there are additional primary factors that are important inputs to the selection process.

Influence of installation and intervention

Both horizontal and vertical tree systems use a landing string to run the completion through the BOP. In the case of the horizontal tree, the completion is normally run on a subsea test tree within the marine riser, and the tubing hanger is landed within the horizontal tree. The subsea test tree is an assembly of connectors and valves and is designed to carry out a number of critical functions.

Once the hanger is landed in the tree, correct orientation of the tubing hanger is critical to ensure communication of all hydraulic and electrical downhole functions. In the case of the horizontal tree, the tubing hanger is normally oriented passively using an orientation sleeve attached to the tree. This passive orientation does not rely on external input.

It is common practice that once a well is completed it will be flowed to the drilling rig to clean up the well or to carry out a well test. This test or cleanup is carried out with horizontal trees via the subsea test tree and a high-pressure riser within the marine riser. The primary function of the subsea test tree ensures that, should it be necessary to disconnect the rig from the BOP during the well test or cleanup, the valves within the test tree can be closed and an emergency disconnect carried out safely.

In the case of vertical trees, the completion is run on a landing string incorporating a tool that runs, locks, and orients the tubing hanger. This orientation function normally requires the tool to interface with a known reference, which commonly comprises a pin installed within the BOP. Once the tubing hanger is oriented correctly it can be landed in the wellhead, with the understanding that when the tree is landed and oriented, communication for all hydraulic and electrical downhole functions will be achieved.

Well cleanup or well testing on a vertical tree is typically only carried out after the well has been suspended and the BOP replaced by a dedicated test package and open-water riser. This test system comprises two main assemblies: the lower riser package (LRP) and the emergency disconnect package (EDP). In a similar fashion to the subsea test tree, this system enables the rig or vessel to safely disconnect in the event of an emergency.

Such LRP/EDP packages and open-water riser systems represent considerable capital investments, typically in the order of tens of millions of dollars. In comparison, subsea test trees can be rented on the open market on a per-day or per-well basis. As a result, they can have a much lower capital impact. This variance in the capital impact of installation and intervention equipment is often a key input into the choice of vertical or horizontal tree technology, particularly when the installed well count is relatively small.

Previously it was noted that an additional tubing-head spool can be run on top of the subsea wellhead. The tubing-head spool is simply an additional spool that is not unlike the body of a horizontal tree but without a production outlet. It broadly carries the same functionality as a horizontal tree body, including passive tubing hanger orientation and A annulus isolation. Using a tubing hanger spool in conjunction with a vertical tree can, in addition to enabling monobore landing string or riser operations, also allow the use of a subsea test tree with a vertical tree.

This potentially negates the significant capital cost of an LRP/EDP and open-water riser system. It is, however, noted that use of a tubing-head spool can require an additional BOP trip.

In the case of a horizontal tree, the tubing hanger and completion are installed within the tree. This requires that the drilling program is closely coupled with the tree delivery schedule. The same is true for a tubing-head spool. The decoupling of tree delivery and the drilling program offers a degree of operational flexibility and again is a factor in tree selection.

Tree system weights

Tree system weight is an important operational parameter. The weight can influence lifting, handling, and installation operations and can have an impact on the required vessel capability. Many end users specify maximum weights for subsea tree systems. As a broad generalization it can be said that the functionally comparable vertical trees are lighter than horizontal trees, primarily driven by the fact that the horizontal tree is designed to interface with a BOP rather than a lighter and less demanding LRP/EDP.

It also is true to say that the functional demands being placed on subsea trees are growing. Valve sizes are increasing; required bending capacities are increasing; and more sensors and instrumentation are required, such as flowmeters.

Key takeaways

Application-specific parameters influencing the choice between either tree include operational risk, water depth, sidetracking, and more.

There is no right or wrong choice – what delivers an advantage in one application may not in another. There are perhaps two key takeaways: First, the demands placed on subsea tree designs will continue to evolve, and application-specific parameters will influence the horizontal/vertical technology evaluation. Second, discussion on this subject will continue to exercise the minds of subsea engineers from around the world for some time to come.

[Article Sharing] Seamless and Welded Pipe

Seamless vs. Welded Tubing | O' Brien Corporation

Source: www.obcorp.com/WorkArea/downloadasset.aspx?id=1432

The difference in the basic manufacturing method is obvious from the names. Seamless tube is extruded and drawn from a billet while welded tube is produced from a strip that is roll formed and welded to produce a tube. Welded tube is considerably less expensive than seamless tube and is readily available in long continuous lengths.

Although the working pressure of welded tube is 20% less than that for a similar seamless tube, working pressure is not the determining factor for choosing seamless tube over welded tube for analyzer sample lines. The difference in potential impurities, which reduce the corrosion resistance of the finished tube, is why seamless tube is specified.

The weld area is considered to be inhomogeneous thus exhibiting different malleability and less corrosion resistance as well as greater dimensional variation. Drawing welded tube reduces these anomalies.

Most tubing (seamless and welded) is drawn to produce final dimensional tolerances. Drawing is an operation, which “pulls” a tube through a die. There are different methods for drawing a tube however they can be thought of as sunk drawn and a plug drawn. The difference is seen in the ID surface roughness. A sunk drawn tube is done without internal support. Sink drawn tube reduces the diameter without controlling the wall thickness. There is some “crunching” of the ID and the tube develops a “sun burst” cross section and wrinkles circumferentially along the inside surface. This can be especially noticeable around the weld on welded tubing. Plug or rod drawn tube is pulled through a die with internal support and produces a much smoother inner surface.

Rod or plug drawing breaks up the weld bead on welded tubing and removes any dimensional indication. Final annealing further promotes a homogeneous tube. The term “full finished” refers to welded tubes that have been rod or plug drawn and annealed sufficiently to both remove any dimensional indication of the weld area and also break up the dendritic structure of the weld bead and expedite homogenization. Often it is very difficult to see the difference between welded and seamless tubing.

By code the allowable working pressure of welded tubing is reduced by 20%.

Working pressure in PSIG for seamless 316SS tubing at 70°F.

The basis for much of today’s bias regarding seamless vs. welded tubing probably stems from early manufacturing processes when the weld area was not reworked to provide a homogeneous tube wall. Even today the standard for working the weld area is very open allowing great variance in the final product. Seamless tubing simply avoids the potential for any defect in the corrosion resistance of the weld area.

Plug drawing tube

[Article Sharing] Flow Assurance for Offshore Pipelines

Flow assurance solutions for offshore pipelines | Bredero Shaw

by Vlad Popovici, Marketing Manager, Bredero Shaw

Source: www.brederoshaw.com/non_html/journals/OTI_Solutions_Aug2012.pdf

The development of the huge oil and gas reserves offshore, especially in deep water, raises specific challenges to operators and contractors. These are not only technical challenges related to the depth of the hydrocarbon-bearing layers, but also related to developing the pipeline transportation infrastructure required to move the hydrocarbons from deep offshore to onshore terminals or refining centers.

Most of the world’s pipelines, including offshore risers, flow lines, and export lines are built using steel pipe. As noted by many industry experts, pipeline integrity for more than the nominal 25-35 years of service is an important aspect in any pipeline’s design, construction and operation. Pipelines should not fail during their service life because such failures could lead to human, environmental, and economic costs. In this context, flow assurance is critical for deepwater projects in order to avoid partial or total pipeline blockages.

End-to-end flow assurance 

There are many ways of approaching the flow assurance issue in offshore pipelines. One of the most commonly used is to apply specially-designed flow assurance coatings on the pipe and field joint area. Most of the industry’s flow assurance coating providers use a “one size fits all” approach by offering only certain types of flow assurance coatings regardless of the project parameters – water depth, maximum operating temperature, installation method – or only linepipe coatings, which leaves the field joint coating falling under the scope of another subcontractor. This can create long-term issues for the pipeline operator, such as suboptimal thermal performance, coating damages, as well as various adhesion issues at the linepipe/field joint coating interface.

Bredero Shaw is the only flow assurance coating provider in the industry that approaches this issue with holistic end-to-end solutions. It provides end-to-end anti-corrosion and flow assurance systems that include the factory-applied line pipe coating and a highly compatible field joint coating installed at a location selected by the customer – onshore on spoolbases or multi-jointing facilities or offshore on pipelay vessels.

An end-to-end flow assurance coating system offers valuable benefits to the offshore pipeline operators and contractors. Operators get guaranteed long-term thermal performance for the entire pipeline, an optimal thermal design that optimizes the flow assurance costs, as well as engineering and thermal design support from the early stages of the project. Pipeline installation contractors benefit from the linepipe/field joint coating compatibility as any interface issues are eliminated.

End-to-end flow assurance coating system installed by Bredero Shaw

Full range of flow assurance solutions 

Bredero Shaw is also the only company in the industry that offers a full range of flow assurance coating solutions, allowing operators to use the optimal system based on the specific project parameters, such as water depth, maximum operating temperature, and installation method. Two of the high-performance flow assurance solutions are briefly described below. 

The Thermotite® PP-based linepipe coatings have been introduced by a predecessor company of Bredero Shaw and gradually developed and improved; they are today applied in various multilayer configurations, including solid, glass syntactic and foam coating systems. The linepipe coating is complemented by the fully-compatible Thermotite® IMPP field joint coating – essentially, a three-layer systems made of an FBE layer, a copolymer adhesive layer and an injection-moulded solid polypropylene insulation layer. The Thermotite® PP-based end-to-end systems have been dramatically improved since the first commercial application in 1991 and are today applied by Bredero Shaw around the world on offshore pipelines with high operating temperatures. 

Using the well-known insulation properties of styrenic polymers the Bredero Shaw R&D team developed Thermotite® ULTRA™, an innovative multilayer coating system with excellent thermal performance, good ductility and excellent impact resistance. The Thermotite® ULTRA™ flow assurance system was launched in 2009 and has already been applied on offshore pipelines in the Gulf of Mexico and the Barents Sea. A key element of the successful launch of this novel coating was again the end-to-end coating approach through the development of an injection-moulded field joint coating that is perfectly compatible with the linepipe coating and that offers equivalent long-term thermal performance.

Portability for flow assurance coatings 

The traditional model for coating steel pipe uses a fixed, specialized coating facility often located at a steel pipe mill. This model is increasingly challenged today by the ability of innovative mobile pipeline coating technologies developed by Bredero Shaw to reduce pipe transportation costs, simplify pipeline project logistics, provide end-to-end coating systems, and increase the local content of the project. 

Brigden™ is an innovative modular portable plant concept developed by Bredero Shaw that is capable of applying a full range of anti-corrosion and flow assurance pipe coating solutions using proven, best in class process technology while delivering the same quality and output as a fixed plant. 

Brigden™ is a turnkey coating facility assembled from process modules supplied in standard size, delivered in specially-designed shipping containers that are ISO certified. The plant can be assembled on site in approximately eight weeks saving much needed time in what is usually a tight schedule. The basic layout can be customized by adding more modules to the baseline layout to expand the plant to accommodate double joints or large diameter pipe. Additional modules can also be added to facilitate the application of any flow assurance and anti-corrosion pipe coating system.  

A Brigden™ portable coating facility is operated by a dedicated team of Bredero Shaw coating and engineering experts – trained in continuous improvement practices and supported by regional operations resources for safe and timely manufacturing and delivery. The plant set-up and coating project execution are based on standard operating practices that are an integral part of the company-wide ShawCor Manufacturing System (SMS).

A Brigden™ mobile plant has the same production capability as a fixed plant. Brigden™ is capable of coating pipe with an outside diameter of 220 to 1066 mm (8-42 in), lengths of 10.4-24.4 m (34-80 ft) and weight up to 484 kg/m (325 lbs/ft). The plant comes fully equipped with integrated facilities for raw materials storage, facility maintenance, and quality control and testing.

All phases of the Brigden™ coating operation, including surface preparation, pre-heat, coating application and final inspection can be conducted in an enclosed area of 1,700 square m (18,000 square ft). A total area of 1.2 ha (2.8 acres) is needed to set-up the entire facility, excluding pipe storage requirements.

For the field joints, Bredero Shaw’s Field Joint Center of Excellence is using the most advanced technologies to develop portable and automated field joint coating equipment that can ensure the consistency and quality of the end-to-end flow assurance coating system, while enhancing operator safety and reducing the operational footprint in the field.

Our field joint coating equipment, materials and operators can be quickly mobilized to any onshore or offshore location. Bredero Shaw offers to global operators and contractors the widest range of thermal insulation field joint coatings in the industry to complement our factory-applied coatings, including the high-performance Thermotite® IMPP and Thermotite® ULTRA™ field joint systems previously discussed.

Brigden™ facility installed for a flow assurance coating project

[Article Sharing] Deepwater Pipeline

Deepwater pipelines – Taking the challenge to new depths | Offshore Magazine

by Martin Connelly - Corus Tubes

Source: www.offshore-mag.com/articles/print/volume-69/issue-7/flowlines-__pipelines/deepwater-pipelines.html

To ensure continuity of supply, E&P companies have to consider opportunities in ever increasing water depths. Assisting this are new technological advances, including pipeline manufacture and design that increase the technical feasibility of deepwater developments.

Deepwater pipeline challenges

Conventional pipeline design, although concerned with many factors, is dominated generally by the need to withstand an internal pressure. The higher the pressure that products can be passed down the line, the higher the flow rate and greater the revenue potential. However, factors critical for deepwater pipelines become dominated by the need to resist external pressure, particularly during installation.

Local infield lines, such as subsea umbilicals, risers, and flowlines (SURF) usually are modest challenges as they are small in diameter and inherently resistant to hydrostatic collapse. In smaller sizes, these lines generally are produced as seamless pipe which is readily available and generally economical.

However, deepwater trunklines and long-distance tiebacks present a greater challenge. To increase subsea production these lines tend to be larger in diameter with a thicker pipe wall to withstand the hydrostatic pressure and bending as it is laid to the seabed.

Typically these lines are often 16 in. to 20 in. (40 cm to 50 cm) in diameter, which presents a further complication as the pipe sizes lie at the top end of economical production for seamless (Pilger) pipes. The Pilger process can produce the thick walled pipe required for these developments but often the manufacturing process is slow, the cost of material high, and the pipe lengths short. As a result, the most economical method to manufacture these lines is the UOE process. The increasingly stringent industry demands have driven this design toward its practical limits of manufacture and installation.

Corus Tubes has responded by manufacturing UOE double submerged arc welded (DSAW) linepipe to the deepest pipelines in the world. This pipe overcomes significant challenges associated with deepwater developments and facilitated a number of pioneering projects such as Bluestream and Perdido.

In the UOE process, steel plate is pressed into a “U” and then into an “O” shape and then is expanded circumferentially. Wall thickness and diameter requirements for deepwater trunkline pipe continue to be challenging for manufacturing economics and installation capabilities.

Distribution curve depicting ovality of Perdido pipe (457 mm x 20.62 mm thick).

While few producers manufacture UOE pipes at 16- to 20-in. outside diameter, this manufacturing method is quicker to market and more cost-effective than seamless alternatives. Corus Tubes’ process seeks to optimize the design of the material and minimize the wall thickness to:
Reduce material cost
Reduce welding cost
Reduce installation time
Reduce pipe weight for logistics and submerged pipe weight considerations
Increase design scope enabling a wider range of deepwater developments.

Det Norske Veritas (DNV) says the acceptability of a pipeline design for a given water depth is determined by means of standard equations that measure the relationship between OD, wall thickness, pipe shape, and material compressive strength.

Pipe shape

Finished pipe shape is optimized by balancing the manufacturing parameters, pipe compression, and expansion. The crimp, U-press, and O-press combination ensures that the pipe size is controlled, often beyond most offshore specifications. Enhanced pipe “roundness”, wall thickness, and diameter tolerance removes uncertainty in the design and production stages and allows pipe wall thickness optimization.

Compressive strength

Pipe manufactured by the UOE process undergoes various strain cycles, both tensile and compressive. The combination of these cycles affects the overall behavior of the material in compression. This is indicated in the equation given in the offshore design standard DNV OS F101 by the presence of the Fabrication Factor αfab. For standard UOE processes, the term represents a de-rating of 15% in the compressive strength as a result of the material response to the strain cycles during forming, known as the Bauschinger Effect.

This diagram represents the relationship between stress and strain when a material is placed in tension (top right quadrant) and then into compression (bottom left quadrant). When material is first placed in tension, such that it is deformed plastically, the yield stress in compression is reduced (compare this with the projected compressive strength in the bottom left quadrant had the pre-tension not been applied).

When material is first placed in tension such that it is deformed plastically, the yield stress in compression is reduced. This originally was reported by Bauschinger in 1881. It is relevant to pipe making because during the forming process the material is placed in tension during expansion. Following this, the material is dispatched for installation, where the pipe sees compressive stress from the pressure of the seawater. Conventionally, the 15% reduction in compressive strength compensates for the Bauschinger Effect.

Since the early 1990s, Corus Tubes has observed that the results it obtained from the forming process often yielded higher compressive strengths than those obtained from the standard equations. Research and process development leads to a greater understanding of the metallurgical transformations during pipe forming. It is possible to reverse the Bauschinger Effect to deliver pipe with compressive strengths higher than conventionally expected.

Three things influence the final pipe mechanical properties in compression:

1. Choice of plate feedstock. The strength of the final pipe is a function of the chemistry and grain structure of the mother plate from which it is fabricated. All aspects of plate manufacture, the chemistry, rolling schedule as well as cooling rates ensure that the final plate properties change to give the required pipe characteristics.
2. Choice of mill compression and expansion parameters. By optimizing the various compression and expansion cycles, a set of manufacturing conditions can be determined to enhance collapse performance to potentially reduce pipe wall thickness in future deepwater applications.
3. Controlled low temperature heat treatment. With the correct plate chemistry it is possible to deliver a lift in compression strength through the application of a low temperature heat treatment. This final part of the process can be measured and assured only if the correct attention has been paid to the previous manufacturing stages.

A number of groundbreaking projects have pushed the boundaries of deepwater exploration and production, and enhanced understanding of pipeline capabilities and limits. In 2000, ExxonMobil used 64 km (40 mi) of line pipe for the Hoover/Diana project which reached depths of 1,450 m (4,800 ft). This also was the first time that small diameter pipe from Corus Tubes’ UOE mill in Hartlepool, UK, was supplied to the deepwater Gulf of Mexico market.

In 2001, Corus Tubes supplied 94 km (45,000 metric tons [49,604 tons]) of three-layer polypropylene coated, high grade, sour service linepipe and bends for the technically challenging Bluestream project which supplies gas from Russia to Turkey under the Black Sea. Corus also was selected to provide pipe for the deepest section of the pipeline at 2,150 m (7,054 ft) water depth.

Corus Tubes recently supplied line pipe to the Perdido Norte project in the Gulf of Mexico. Williams commissioned the production of small diameter UOE pipe and approximately 312 km (194 mi) of uncoated steel line pipe for ultra deepwater depths from 3,500-8,300 ft (1,067-2,530 m) with a rugged seabed terrain. The pipe, manufactured to withstand a service rating equivalent to ANSI 1500, is one of the deepest pipelines in the world.

One section of the pipeline transfers hydrocarbons from the FPS host in Alaminos Canyon block 857 and terminates in East Breaks block 994 (78 mi [126 km]). The gas pipeline terminates at Williams Seahawk pipeline in East Breaks block 599 (106 mi [171 km]). The 18-in. (46-cm) diameter pipe was manufactured in wall thicknesses ranging from 19.1 mm to 27.0 mm (¾ in. to 1 in.).

Further to the experiences on Perdido, Corus has produced a thicker pipe at 18-in. diameter for the Petrobras Tupi project. The pipe has a wall thickness of 31.75 mm (1 ¼ in.) and lies in a water depth of 2,200 m (7,218 ft) offshore Brazil. While this project is not the deepest, it represents a milestone in pipe forming. This is the thickest UOE pipe ever manufactured at 18-in. diameter (note as the diameter of a pipe reduces and thickness increases, the levels of strain and power required to forming it increases).

Tupi is a testimony to the complexity of deepwater pipe design. While collapse at these water depths is a critical design state, there also were concerns about corrosion, since the Tupi production has some small amounts of contaminants in the exportation gas (about 5% CO2 and a very small amount of H2S). Even though the exported gas should be dehydrated, the CO2 raises concerns about pipe corrosion and is managed by increasing the nominal wall thickness to account for loss of material during life. At the end of the pipe life it still must withstand the pressure at the seabed even with a reduced wall thickness.

The H2S, although not expected in the exported gas, could cause cracking to occur in steels where the grain structure and cleanliness is not optimized. In addition, high levels of forming strain can exacerbate the situation. Corus Tubes applied its knowledge of steel production and pipe forming to ensure that the plate it procured from Dillinger Hutte and Voest Alpine provided ultimate resistance to H2S corrosion.

Pipelines in deepwater require the tightest dimensional tolerances to maximize resistance to collapse and to maximize girth weld fatigue resistance. Furthermore, pipelines from 16-in. to 28-in. (71-cm) are seen as the future for deepwater export pipeline systems.