South Stream cleared for

Turkish route through

Black SeaMOSCOW – Turkey’s Ministry of Environment and Urban Planning has approved the

environmental impact assessment (EIA) report for the South Stream gas pipeline’s section through

Turkish waters.

The pipelines will be laid more than 110 km (68 mi) offshore Turkey in the Black Sea in water

depths of up to 2,200 m (7,218 ft). Installation of the first string will start in Russian waters later this

year.

The first pipelay vessel will enter the Turkish exclusive economic zone during 1Q 2015, and the

completed first offshore pipeline will be commissioned by late 2015.

The report assesses potential environmental impacts caused by the construction program,

including on the seabed geology, water quality, and marine ecology.

In addition, the report proposes various measures for the lay route including bypasses the

locations of shipwrecks.

07/30/2014

http://www.offshore-mag.com/articles/2014/07/south-stream-cleared-for-turkish-route-through-black-

sea.html

On-Bottom Stability Design of Submarine Pipelines2. Design

2.1 Target failure probability

Excessive lateral displacement due to the action of hydrodynamic loads is considered to be a

serviceability limit state SLS with the target safety levels given in DNV-OS-F101., Ref. /1/. If this

displacement leads to significant strains and stresses in the pipe itself, these load effects should be dealt

with in accordance with e.g. DNV-OS-F101.

2.2 Load combinations

The characteristic load condition shall reflect the most probable extreme response over a specified

design time period. For permanent operational conditions and temporary phases with duration in excess

of 12 months, a 100-year return period applies, i.e. the characteristic load condition is the load condition

with 10-2 annual exceedance probability. When detailed information about the joint probability of

waves and current is not available, this condition may be approximated by the most severe condition

among the following two combinations:

1) The 100-year return condition for waves combined with the 10-year return condition for current.

2) The 10-year return condition for waves combined with the 100-year return condition for current.

For a temporary phase with duration less than 12 months but in excess of three days, a 10-year return

period for the actual seasonal environmental condition applies. An approximation to this condition is to

use the most severe condition among the following two combinations:

1) The seasonal 10-year return condition for waves combined with the seasonal 1-year return condition

for seasonal current.

2) The seasonal 1-year return condition for waves combined with the seasonal 10-year return condition

for current.

One must make sure that the season covered by the environmental data is sufficient to cover

uncertainties in he beginning and ending of the temporary condition, e.g. delays. For a temporary phase

less than three days an extreme load condition may be specified based on reliable weather forecasts.

Guidance note:

The term load condition refers to flow velocity close to the seabed. The highest wave induced water

particle velocity does normally not correspond to the highest wave and its associated period, but for a

slightly smaller wave with a longer period. This effect is more pronounced in deeper waters.

2.3 Weight calculations

Pipe weight should be based on nominal thicknesses of steel wall and coating layers. If metal loss due to

corrosion, erosion and/or wear is significant, the wall thickness shall be reduced to compensate for the

expected average weight reduction. Pipe content can be included with its minimum nominal mass

density in the relevant condition.

2.4 Resistance calculations

Resistance, both the Coulomb friction part and that from passive resistance should be calculated based

on nominal pipe weight.

2.5 Design criterion

Away from end constraints, the design criterion for lateral stability may be written on a general form as:

where Yall owable is the allowed lateral displacement scaled to the pipe diameter. If other limit states,

e.g.maximum bending and fatigue, is not investigated, it is recommended to limit the sum of the lateral

displacement in the temporary condition and during operation to 10 pipe diameters. When considering

the displacement criterion, one should keep in mind that instability in this sense is an accumulated

“damage” that may also get contributions for storms that are less severe than the design storm that is

normally analysed. For larger displacements one should perform a full dynamic analysis with adequate

analysis tools, or e.g. data bases established by such analyses. Special considerations with respect to

bending and fatigue should be made.

The design curves given in Section 3.5 are based on maximum displacement from several dynamic

analyses with varying seed value for the random phase shift and can thus be regarded as upper bound

values. I.e. no additional safety factors are required. It should be noted that these analyses are one

dimensional, neglecting pipe bending – and axial stiffness, and that close to constraints and/or if very

large displacements are allowed, two (or three) dimensional analyses may be required.

RECOMMENDED PRACTICE

DNV-RP-F109

OCTOBER 2010

Innovation enhances

deepwater flexible pipe lifeManaging riser friction damage, corrosion cuts repair costs

Judimar Clevelario, Helio MarinsMarcio Albuquerque, Wellstream International Ltd.

As flexible pipe applications move into deepwater and ultra deepwater,

attention is focused on enhancing service life, particularly with respect to

corrosion and wearing. In Brazil’s offshore Campos basin, Petrobras and

Wellstream International Ltd. have addressed both issues for unbounded

dynamic flexible risers and static flowlines.

Flexible pipe cutaway.

The first means of enhancing service life is the use of a latch sleeve insert to

address damage in flexible risers caused by friction between the outer

polymer sheath of the riser and the I-tube at the vessel hang-off. The second

is the use of anode clamps to protect flexible pipe endfittings against

corrosion.

Petrobras’ original I-tube latch sleeve had a metallic “trumpet” that

interfaces directly with the bend stiffener within the I-tube for a metal-

polymer contact between the flexible riser outer sheath and the latch sleeve.

New latch sleeve design.

This metal-polymer contact, when subjected to cyclic bending, tension,

friction, and pressure loads from the FPU’s dynamic response, resulted in

excessive wear and abrasion damage of the riser polymeric outer sheath. In

some cases, the outer sheath was damaged to the point that the outer

tensile wires were exposed to the marine environment and subject to failure

from corrosion and metal-metal contact. Furthermore, Petrobras found that

outer sheath wear damage was critical on FPSO installations. Damage came

from axial displacement of the riser inside the I-tube causing outer sheath

(polymer) friction against the internal surface of the latch sleeve (metallic).

Wellstream developed a new latch sleeve design to eliminate excessive wear

of the riser outer sheath material within the contact region. The sleeve was

designed for a 20-year dynamic service life in a typical Campos basin

application.

The latch sleeve mechanism has an internal replaceable insert made of

similar materials to those used in typical bend stiffener moldings. The

polymer-polymer contact is similar to that between the riser outer sheath

and the bend stiffener. The new latch sleeve still has a trumpet design for a

smooth transition of the flexible riser within the contact region.

The design was based on the following:

In-service survey data

Petrobras’ requirements

Bend stiffener supplier design and field experience

Full-scale dynamic fatigue tests and subsequent detailed dissection.

The most cost-effective solution was a split polymeric replaceable insert

made with the same polyurethane material as the bending stiffener,

assembled on the internal diameter of the latch sleeve adapter. The

polymeric insert prevents direct metal-polymer contact, which is the major

cause of wear.

In developing the design, the design team analyzed concerns such as design

performance, assembly, installation, and maintenance. Upon completion, the

design was submitted to the customer, and following approval, was installed

on the Marlim and Marlim Sul fields. The latch sleeves were scheduled for

installation on all Wellstream flexible pipes using the I-tube latch sleeve

mechanism on Petrobras’ FPSOs.

The design team developed a non-linear finite element model that

reproduces the contact among the bend stiffener, latch sleeve, and riser to

confirm qualitatively that the compression load magnitude at the contact

surface of the pipe outer sheath and inner bending stiffener has the same

magnitude as the pipe outer sheath and inner latch sleeve insert.

Analysis results confirmed that the contact pressure between the pipe outer

sheath and inner bending stiffener, and pipe outer sheath and inner latch

sleeve insert have the same magnitude. The team concluded that using the

same bending stiffener material should avoid excessive wearing damage.

It is important to guarantee that wearing occurs in the polymer insert before

it does in the outer sheath. An abrasion test results-graph of high and

medium performance polyurethane (in accordance with DIN 53516) shows

that medium-performance polyurethane is more susceptible to wear than

high-performance polyurethane, nylon (PA-11), or HDPE - all typical riser

outer sheath materials. Therefore, medium-performance polyurethanes were

used in the new latch sleeve.

Anode clampThe second area addressed by the design team was corrosion. Offshore

equipment is subject to severe corrosion. Although equipment often is

manufactured of special materials to prevent or minimize corrosion, cathodic

protection still can be required.

Anode clamp design.

Petrobras expressed concern about ancillaries on several installed flexible

pipe. One of the most critical ancillaries is the endfitting, a metallic device

that connects the flexible pipe to a pipeline end termination (PLET) or a

pipeline end manifold (PLEM).

The starting point of the project was the development of cathodic protection

that did not require removal of the endfitting. Removal would increase the

installation cost and possibly halt production.

Wellstream developed a metallic structure with clamps that can be installed

by an ROV without removing the endfitting or stopping production.

The result was an anode clamp consisting of a metallic structure with clamps

and clamp grooves for surface cleaning to guarantee a contact between

clamp surface and surface to be protected, with aluminum anodes attached.

In June 2003, the first anode clamp was installed on the subsea endfitting

abandoned on Barracuda field, near RJS-458, in 800 m (2.625 ft) water

depth. In May 2004, Petrobras requested a new anode clamp design for

installation on an endfitting near the RO-09 well on the Roncador field in

1,800 m (5,905 ft) water depth. The second anode clamp was installed in

August 2004.

A major concern during the anode clamp design was guaranteeing electrical

contact between the clamp and the endfitting. Primarily, the electrical

contact is made through the clutches. Internal grooves were designed to aid

the surface cleaning and to enhance contact capability. Additionally, contact

pins on the equipment were designed to give extra contact between the

anode clamp and endfitting.

Anode clamp installation process.

Another issue was to make installation easy. The design team created a

clamp that could be installed by an ROV; no special vessel is required.

Furthermore, production need not stop during installation. Before the actual

clamp placement, an ROV cleans the endfitting surface with a steel brush for

better electrical contact. Then, the anode is set over the fitting and clamped

into place. Then, the contact pin is set.

Wellstream carried out testing that led to the conclusion that the system

could be used on flexible pipes. Inquiries revealed that all of the materials

required were available locally.

To confirm the function of the anode, the electrical potential of the endfitting

was measured before and after the clamp was installed. The measure

indicated the cathodic protection was in place.

AcknowledgementThe authors thank Petrobras S.A. for contributions to both projects.11/01/2007

http://www.offshore-mag.com/articles/print/volume-67/issue-11/transportation-amp-logistics/

innovation-enhances-deepwater-flexible-pipe-life.html

Metoda Instalasi Pipeline di Ormen Lange Gas Field Ormen Lange Gas Field terletak 120 km dari pantai Norwegia merupakan lokasi cadangan gas sedalam 3000m dari permukaan laut dan memiliki deposit sebanyak 300 juta m3, mengandung cukup gas untuk mensuplai 20% kebutuhan gas UK dalam 40 tahun.

Proyek eksplorasi ini direncanakan berjalan selama 10 tahun dengan nilai sebesar $10 juta untuk mengebor deposit dan mentransfer gas sejauh 120km ke fasilitas proses darat Norwegia untuk kemudian ditransfer sepanjang 1200km melalui jalur pipa (pipeline) ke UK. Jalur pipeline digambarkan sebagai berikut:

Gambar jalur pipeline.

Tahap pemasangan pipeline dalam proyek ini, yakni;

Tahap 1 perletakan pipa dilakukan di assembly floor pada barge yakni dengan membuat joint

ganda agar didapat pipa sepanjang 24m. Gambar tahap ini sebagai berikut;

Gambar pembuatan joint ganda.

Tahap 2 dilakukan assembly lines untuk menggabungkan bagian pipa sekunder ke pipeline

utama.

Gambar pipa yang akan digabungkan.

Pada tahap ini digunakan mesin las khusus sebagai berikut;

Gambar pengelasan pada tahap assembly lines.

Setiap pipa yang telah selesai dilas, dilakukan pengecekan ultrasonik.

Tahap 3 yakni penyegelan koneksi metal yang tidak tertutup pada pipa menggunakan plastik

pelindung untuk mencegah korosi sebagai berikut;

Gambar penyegelan koneksi metal pipi dengan plastik pelindung.

Tahap 4 dilakukan offloading pipa. Bagian sambungan pipa terlebih dahulu dilapisi dengan foam

pelindung agar bagian lasan tidak rusak. Proses offloading pipeline ditunjukkan pada gambar

berikut;

Gambar proses offloading pipeline.

Tahap 5 dilakukan proses trenching pada pipeline selebar 5m dan sedalam 2m diikuti dengan

backfill untuk menutup trench dengan lapisan pasir. Gambar proses trenching sebagai berikut;

Gambar proses trenching.

High integrity alloys:

Selection issues for

corrosion protectionAlan Robinson

Arc Energy Resources

Consider the problems. Hydrogen sulfide (H2S), dissolved carbon dioxide (CO2) and various chlorides are

all present in the hydrocarbons delivered from subsea fields, and they can be accompanied by high

pressures and high temperatures. And sour service at high temperature is more corrosive, while the

same service at high pressure is more erosive. A combination of the two is a potentially expensive and

hazardous situation that impacts materials selection, in terms of protecting low-cost carbon steels or

manufacturing in high-cost corrosion resistant alloys.

Rotating head.

Corrosion and corrosion prevention cost the subsea oil and gas industry billions of dollars every year, so

the decisions taken are vital. The selection of the materials and the preventative processes used to

extend the operating life of materials is essential to the cost-effective manufacture and safe long-term

operation of equipment such as pipelines and valves, especially in deepwater operations.

When assessing corrosion protection for any production system pipeline, process engineers have

numerous options. The effectiveness of each will vary according to factors such as the aggressiveness of

the product; pressure and temperature; the size and complexity of the system; projected life expectancy

of the well; the development period available; and, perhaps most important, overall budget constraints.

So how can welding engineers help the oil and gas industry to resist these attacks?

Protection, where risk of attack is low and life cycle relatively short, may be as simple as using an

injected inhibitor with conventional high-strength carbon or low-alloy steel. Where greater protection is

needed, corrosion-resistant alloys (CRAs) must be considered. These include austenitic (300 series)

stainless steels, ferritic/martensitic (400 series) stainless steels, duplex stainless steels, or the more

complex high nickel chromium alloys.

Duplex steels and nickel-based alloys, such as alloy 625, are the only materials in general production

which, when welded, achieve suitable levels of protection. However, there are constraints on the use of

these materials in their solid form – namely cost, availability, and the need for very tightly controlled

welding procedures.

Cost is particularly relevant where large quantities of pipe and fittings are needed or when large forgings

or castings are used. Typical examples are wellhead valve systems and pipe bundle bulkheads.

The use of carbon and low-alloy steels clad with a corrosion-resistant alloy is common practice for some

years now. It is a well-proven, economical, and technical alternative to solid alloys. It offers the benefits

of strength and/or availability of base materials combined with corrosion resistance, when applied in

selected areas.

Weld overlay cladding presents the materials engineer with a choice of processes and more flexibility.

An almost infinite range of component shapes and sizes can be protected, with an equally wide range of

base material/cladding alloy alternatives. Weld procedures are normally qualified to ASME IX, as are the

welding operators.

Additional testing to prove conformity with API 6A and NACE MR01-75 also is essential. Selection of the

most appropriate welding process largely depends on factors such as the size and geometry of the clad

area; access to the area to be clad; alloy type; specified clad thickness; chemical composition limits;

welding position; and NDT acceptance standards.

There are many common welding processes but given that the process used must be practical, viable,

and provide the mechanical and chemical conditions to achieve service requirements, economics dictate

that the higher deposition rate processes should prevail.

GTAW (gas tungsten arc welding) provides excellent control and a high quality result. It can be used in

bores as small as 20 mm (0.78-in.), and is suited for components of varied geometry, where the position

of the welding head requires frequent adjustment. These could range from a simple flange that needs to

be clad through the bore and across the sealing face, to a complex valve body with several

interconnecting bores. Utilizing twin wire, hot wire, and multi-head configurations increases the

deposition rates.

Often such equipment also needs cladding to RTJ (ring-type joint flange) grooves. The control available

with GTAW means cladding can follow the profile of the groove rather than filling it completely. This not

only saves time and material during cladding, it also reduces the cost of subsequent finish machining.

Using this process the chemical composition of the welding consumable can be achieved at <2.0 mm

(0.08-in.) from the base material/cladding interface (this can be reduced to <1.0 mm (0.40-in.), in the

case of 300 series stainless steels, where over-alloyed wires are available).

Plasma-transferred arc is another option. The process equipment costs are higher and the process

variables slightly more complex than GTAW, but the increased control available on the arc makes it

more amenable to CNC control. When combined with oscillation, dilution levels down to 3% have been

achieved at 1 mm from the interface.

Arc's development engineers have been working with the new breeds of GMAW (gas metal arc welding)

to improve control of the arc, and the resulting process likely will supplant some current GTAW

applications.

For more open access applications, the electroslag process is economically attractive. It does employ a

large weld pool that requires substantial base metal backing (generally a minimum of 20 mm) in order to

prevent excessive dilution. The deposit thickness is nominally 5 mm (0.2 in.) with the strip widths

discussed here. With 60-mm (2.4-in.) strip, deposition rates of up to 22 kg/hr (48.5 lb/hr) can be

achieved.

To enable the chemical composition of the deposit to match that of the consumable specification within

the first layer (3 mm, or 0.12 in., from the interface), over-alloyed strip and "loaded" metal containing

fluxes are available.

Problems associated with electroslag strip cladding involve the limited availability of strip, which tends

to increase the cost of the material; and the difficulty of feeding the strip when cladding within bores of

pipe. Arc Energy Resources is developing a multi-wire electroslag configuration for pipe cladding. This

should solve both problems and provide a combination of high deposition, excellent profile, and good

quality.

Submerged arc welding using a solid wire consumable, while not as fast, is a useful "halfway house"

between strip cladding and the slower GTAW and pulsed GMAW. The welding heads are not as large as

strip heads, and the consumable delivery method is more flexible. Hence, the capability to use this in

smaller bore diameters. Traditionally larger-diameter (2.4 mm+, or 0.09-in.+) consumables have been

used for this process, again resulting in the need for fairly thick substrates to accept the high heat inputs

and large weld deposits.

11/01/2011

http://www.offshore-mag.com/articles/print/volume-71/issue-11/equipment-__engineering/high-

integrity-alloys-selection-issues-for-corrosion-protection.html

PIPELINES Vessel-

deployed, free span

support system speeds

Transmed installation

Atlantis pipeline mechanical support system readied for operation on

the Transmed gas line.

Stabilization of submarine pipeline free spans along uneven sea bottoms is conventionally performed

using gravel dumping, post trenching or mattresses. However, as SEIC, based in Fano, Italy points out,

these technologies merely support the pipeline: they cannot lift it.

SEIC has developed a new technique which has been applied to support free spans along the 26-inch

diameter Transmed gas lines crossing the Sicily Channel in water depths down to 510 metres. The

technology is based on the pipeline mechanical support system Atlantis with its installation module

Pegasus: it was developed to cater for requirements such as short installation time, simple interface

with the support vessel and pipeline lifting capacity.

Reduced installation time is achieved by automatic operational procedures, including an auto heading

function, which are acoustically controlled from the surface. No umbilical cable, winch, slip ring or

power distribution unit are necessary, meaning that a vessel equipped with a conventional crane and a

support ROV are sufficient to install the system.

The Pegaso module is powered by dedicated battery packs and the ROV is used to provide video images

during marine operations and to drive Pegaso hydraulic functions in emergency conditions. Three types

of supports, with different leg length and minimum/maximum clamping distance, were built and

installed along Transmed in order to satisfy intervention requirements on the expected as-laid

configurations.

Atlantis can be installed and subsequently adjusted or removed in water depths down to 1,000 metres.

Two different installation procedures, one at pre-set lifting displacement and the other at pre-set lifting

force, can be employed to solve free span problems in terms of pipeline stress level.

No hydraulic component is installed on Atlantis, the mechanisms of which are operated automatically by

hydraulic actuators placed onboard Pegaso. Redundancy has been achieved by implementing four

different operating modes - automatic, manual, mechanical and emergency - at different levels of

system fault.

According to SEIC, the Atlantis/Pegaso system has numerous other advantages over competing

techniques. Gravel, it points out, is subject to scouring and may not ensure a firm support to the

pipeline; and post-lay trenching is often impossible due to bottom morphology and geotechnical

characteristics. The adjustment and recovery procedures of the SEIC system brings operational flexibility

compared with other passive supporting systems, which cannot be removed once installed.

Copyright 1996 Offshore. All Rights Reserved.

02/01/1996

http://www.offshore-mag.com/articles/print/volume-56/issue-2/news/pipeline/pipelines-vessel-

deployed-free-span-support-system-speeds-transmed-installation.html

Eupec to manage Nord

Stream pipeline coating

processEarlier this year, Dunkerque-based Eupec signed a letter of intent to supply concrete weight coating and

logistics services for the Nord Stream pipeline project. This will take gas from Russia across the Baltic Sea

to mainland Europe via two lines, each 1,210 km (752 mi) long, with a combined capacity of 55 bcm/yr

(1.9 tcf/yr).

Germany’s Europipe and Russia’s OMW will manufacture the pipeline sections from high tensile steel,

with wall thickness varying from 27-41 mm (1.06-1.61 in.), in accordance with pressure decline along the

proposed route. Internally, the pipes will be coated with an anti-friction coating, while externally, they

will be protected with a layer of anti-corrosion coating.

Schematic shows Eupec’s five-layer polypropylene foam coating system.

To provide extra weight and stability on the seabed, the steel pipe joints, each 12 m (39.4 ft) long, will

also undergo external concrete coating with a thickness varying from 60-110 mm (2.36-4.33 in.). A

comprehensive inspection program will then be applied involving ultrasonic, magnetic particle,

radiographic and other non-destructive testing techniques, to ensure the joints can withstand the

pipelines’ maximum internal pressure of over 200 bar (20 MPa).

Concrete weight coating will be performed at new coating plants to be constructed on the Baltic coast at

Kotka in Finland and Mukran on the island of Ruegen, off northern Germany. The Nord Stream partners

have selected Slite on the island of Gotland, off eastern Sweden, as the site of the main interim stock

yard, with Hanko in southern Finland and Karlshamm in southern Sweden identified as strategic

locations for additional interim stock yards, the aim being to keep transportation distances within 100

mi (161 km).

Eupec, as Nord Stream’s logistics partner, will manage discussions with authorities at these locations

about the type of facilities needed to ensure deliveries of weight coating and logistics services. The five

proposed sites should employ up to 375 personnel for this project.

The two coating plants will employ the same coating processes applied by Eupec at its factory in Grande

Synthe, France. For the first line, 75% of the pipes will be manufactured in Germany, with Mukran

coating 770 km (478 mi) of those pipes. The coating plant will occupy an area of 10,220 sq m (110,007 sq

ft), with a slightly larger area for the steam-curing facility.

First pipe sections were due to reach Mukran and Kotka in April and June, respectively, with pipe coating

scheduled to start at Mukran next January and at Kotka in March 2009.

Coating for the first of the Nord Stream pipelines should be completed by the following December. All

completed pipes will then be transported to the interim stick yards and from there to the designated lay

barge. The total budget for the coating and logistics contract is €650 million ($1.025 billion), with around

€100 million ($157 million) allocated to establishment of coating and logistics infrastructure.

The intake point for the Nord Stream system will be Vyborg in Russia, the delivery point in Germany

being a reception terminal in Lubmin, near Greifswald. The first of the pipelines should be operational in

spring 2011, with annual throughput capacity of 55 bcm/yr (1.9 tcf/yr) being reached the following year

on completion of the second phase.

Wet/dry insulation

Eupec provides thermal insulation coating services for shallow and deepwater steel pipelines, currently

at depths up to 3,000 m (9,842 ft). These include polyurethane-based systems for wet insulation (solid,

foam, syntactic, or glass syntactic). They are applied either via injection molding, rotational casting,

spraying, or in the form of polyurethane half-shells.

The company also supplies multi-layer anti-corrosion coating systems in a wide range of layers and

thicknesses. Linepipe coating is applied by side extrusion, with a patented injection moulding technique

implemented for field joints, both suited for reel lay, J-lay, and S-lay installations.

One of the company’s more strategic product developments for 2008 is a five-layer foam polypropylene

coating system for applications involving transportation of a high temperature well stream, where a

minimal temperature drop is stipulated - i.e. to avoid shut down due to hydrates formation, to reduce

fluid viscosity, or to increase pipeline flow.

The coating system, applied via a side extrusion process and an electrostatic spraying technique,

involves application of five different layers of coating:

1st layer (fusion bonded epoxy- FBE) provides the main anti-corrosion properties

2nd layer (polypropylene –PP –adhesive) is designed to ensure high strength properties

between the PP and the FBE. The adhesive should be sufficiently thick to absorb interfacial

stress between the epoxy layer and the solid PP layer

3rd layer (solid polypropylene) is an intermediate layer providing a safe anti-corrosion

protection, also ensuring that water ingress does not reach the steel pipe

4th layer (foam polypropylene), is also the thickest, designed to assure the thermal insulation

properties of the five-layer coating

5th layer (solid polypropylene), is the system’s outer sheath, which is stabilized against ultra-

violet radiation and also thermally stabilized against ageing by thermal and UV degradation. This

outer coat also reduces the speed of water ingress through the insulation PP foam, and provides

additional mechanical protection of the PP foam layer.

Immediately after each coat has been applied, cooling is applied with fresh water.

In recent years, Eupec has also managed fabrication of Interpipe’s pipe-in-pipe (PIP) systems in

Dunkerque, its scope including pipe coating, PIP sleeve installation, welding, and logistics.

05/01/2008

http://www.offshore-mag.com/articles/print/volume-68/issue-5/france/eupec-to-manage-nord-stream-

pipeline-coating-process.html

Innovative engineering

solves subsea pipeline tie-

in challengeCustom hot tapping machine plays pivotal role

Michel Courbat

T.D. Williamson S.A.Technip was recently contracted by Burullus Gas Co. (Burullus) to tie in an expansion to its existing

subsea West Delta Deep Marine (WDDM) facilities. To accomplish this, it was necessary to tie in a new

36-in. gas trunkline pipeline, which is part of the Phase VII project, to the existing system under pressure

without shutting down production. To perform the tie-in, Technip retained T.D. Williamson S.A. (TDW)

to carry out three subsea hot tap intervention operations.

Two traditional 16-in. hot tap operations would be completed on a 26-in. pipeline, and one innovative

20-in. hot tap on a 36-in. pipeline. To ensure that the hot tap interventions would be successful, it was

necessary to engineer, install and pre-commission two hot tap assemblies, including one capable of

cutting through a blind weld-neck "tappable flange" made of duplex stainless steel on the 36-in. line.

Hot tap machine

In preparation for the operation that would take place in depths to 95 m (311 ft), TDW worked with a

Belgium-based engineering and construction specialist to produce the special hot tap tool known as a

"cutter." This special tool would be used for the 20-in. hot tap and would need the ability to effectively

cut the duplex plate. Since the duplex has a very high mechanical strength – meaning that it has a high

elongation before reaching breaking point and a high level of hardenability – the cutting process

employed must be very rigid and vibration-free while using the TDW Model 936D subsea tapping

machine.

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

Working at TDW's facility in Nivelles, Belgium, a series of engineering, design and preliminary tests was

performed. The first step involved engineering several alternative designs. The first alternative consisted

of using either a proven cutter design; or that proven design updated with various teeth geometry.

However, this option was not pursued because it could not penetrate the duplex stainless steel.

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

A second option involving removable teeth and welded teeth support was considered, but this was

rejected due to its inability to resist vibration.

Ultimately, the design selected for fabrication featured a subsea electro-pump to supply adequate

hydraulic power, a pilot drill with bronze plates to reduce vibration, and a specially manufactured set of

cutters with removable cutting teeth that would be able to penetrate duplex stainless steel without

breaking.

Preliminary trials

After the design was finalized, materials were procured and the prototype was fabricated and made

ready for the first phase of testing: the internal preliminary trials.

A diver prepares for the vertical hot tapping operation.

During a period of eight weeks, the prototype was subjected to rigorous testing associated with a

number of capabilities. The cutter's ability to make deep cuts on a plate of the same type of duplex

stainless steel as the blind weld-neck "tappable flange" on the pipeline was an initial challenge.

A diver carries out the horizontal hot tapping operation.

The team made material and design improvements, ultimately achieving a prototype that could produce

a smooth and satisfactory cutline. In addition, special bronze guides were developed and installed on

the pilot drill to control vibration.

By the end of the four-month trial period, several renditions of the prototype had been used to

complete four tapping operations. Before and after each cutting trial, visual and nondestructive

examinations (NDE) of the cutters and pilot drills were carried out. The final prototype, which featured

dual sets of cutting teeth and the pilot drill with the bronze guides, performed well. As the hot tap

machine would be required to operate at an average pressure of 100 bar, pressure tests were

undertaken to satisfy the requirements of the forthcoming factory acceptance test. The decision was

then made to proceed to the second stage: the official trials.

Official trials

During the official trials three tapping operations were carried out with the custom machine. Two hot

taps were completed on duplex plate, and one cold tap was executed through equal duplex tappable

plate. These tapping operations revealed that the equipment endured the rigorous process, remained

properly aligned and cut the duplex steel plate effectively. These operations took place as part of a

requisite system integration test (SIT), which confirmed the following:

The teeth accurately cut the duplex stainless steel

The pilot drill remained rigid and vibration-free

The design of the cutter was improved by adjusting the teeth support.

It also proved that the tapping machine could be unset in the middle of the cut and reset while reaching

the cut back without causing the tapping machine to be misaligned or moved out of proper position.

With the official trials of the custom hot tap cutter successfully completed, the system received

approvals from Burullus, Technip, and the Burullus Independent Verification Authority to perform the

subsea operation well in advance of the project mobilization. In preparation for the impending

operation, two hot tap machines were produced in order to guarantee 100% back-up of this critical

piece of equipment.

Maintaining gas pressure

For three weeks, TDW worked from Technip's dive support vessel Wellservicer to carry out all three hot

taps. Throughout the process, a prevailing pressure of 100 bar (1,450 psi) was successfully maintained in

the existing gas export system. The innovative hot tap on the duplex tappable flange required just six

days to complete.

In spite of the fact that the hot tap intervention was carried out subsea, making it more complicated to

mobilize and install equipment than when working onshore, the operation was carried out by skilled

divers as intended, with no lost time incidents or production downtime.

Much of the success was attributed to the investment in planning and pre-operational equipment trials

and testing. TDW worked with the Technip and Burullus teams to ensure that the operation would

proceed like clock-work, and that the customized cutting tool would operate effectively on duplex

stainless steel. As a result, the operation provided three tie in points, preparing the way for Technip to

successfully tie-in the new 36-in. gas trunkline for the WDDM Phase VII development.

The author

Michel Courbat is offshore project manager for T.D. Williamson S.A.

11/01/2011

http://www.offshore-mag.com/articles/print/volume-71/issue-11/flowlines-__pipelines/innovative-

engineering-solves-subsea-pipeline-tie-in-challenge.html

Understanding pipeline

buckling in deepwater

applicationsFinite element model predicts local conditions

D. DeGeer - C-FER Technologies

With ultra deepwater pipelines being considered for water depths of nearly 3,000 m, pipe collapse, in

many instances, will govern design. For example, bending loads imposed on the pipeline near the

seabed (sagbend region) during installation will reduce the external pressure resistance of the pipeline,

and this design case will influence (and generally govern) the final selection of an appropriate pipeline

wall thickness.

To date, the deepest operating pipelines have been laid using the J-lay method, where the pipeline

departs the lay vessel in a near-vertical orientation, and the only bending condition resulting from

installation is near the touchdown point in the sagbend. More recently, however, the S-lay method is

being considered for installation of pipelines to water depths of nearly 2,800 m. During deepwater S-lay,

the pipeline originates in a horizontal orientation, bends around a stinger located at the stern or bow of

the vessel, and then departs the lay vessel in a near-vertical orientation. During S-lay, the installed pipe

experiences bending around the stinger (overbend region), followed by combined bending and external

pressure in the sagbend region.

Initial bending in the overbend during pipe installation may result in stress concentrations in pipe-to-pipe weld offsets

or in pipe-to-buckle

In light of these bending and external pressure-loading conditions, analytical work was performed to

better understand the local buckling behavior of thick-walled line pipe due to bending, and the influence

of bending on pipe collapse. Variables considered in the analytical evaluations include pipe material

properties, geometric properties, pipe thermal treatment, the definition of critical strain, and

imperfections such as ovality and girth weld offset.

Design considerations

As the offshore industry engages in deeper water pipeline installations, design limits associated with

local buckling must be considered and adequately addressed. Instances of local buckling include

excessive bending resulting in axial compressive local buckling, excessive external pressure resulting in

hoop compressive local buckling, or combinations of axial and hoop loading creating either local

buckling states. In particular, deepwater pipe installation presents perhaps the greatest risk of local

buckling, and a thorough understanding of these limiting states and loading combinations must be

gained in order to properly address installation design issues.

Initial bending in the overbend may result in stress concentrations in pipe-to-pipe weld offsets or in

pipe-to-buckle arrestor interfaces. Initial overbend strains, if large enough, may also give rise to

increases in pipe ovalization, perhaps reducing its collapse strength when installed at depth. Active

bending strains in the sagbend will also reduce pipe collapse strength, as has been previously

demonstrated experimentally.

Overall modeling approach

In an attempt to better understand pipe behavior and capacities under the various installation loading

conditions, the development and validation of an all-inclusive finite element model was performed to

address the local buckling limit states of concern during deepwater pipe installation. The model can

accurately predict pipe local buckling due to bending, due to external pressure, and to predict the

influence of initial permanent bending deformations on pipe collapse. Although model validation is

currently being performed for the case of active bending and external pressure (sagbend), no data has

been provided for this case.

The finite element model developed includes non-linear material and geometry effects that are required

to accurately predict buckling limit states. Analysis input files were generated using our proprietary

parametric generator for pipe type models that allows for variation of pipe geometry (including

imperfections), material properties, mesh densities, boundary conditions and applied loads.

A shell type element was selected for the model due to increased numerical efficiency with sufficient

accuracy to predict global responses. The Abaqus S4R element is a four-node, stress/displacement shell

element with large-displacement and reduced integration capabilities.

All material properties were modeled using a conventional plasticity model (von Mises) with isotropic

hardening. Material stress-strain data was characterized by fitting experimental, uniaxial test results to

the Ramberg-Osgood equation.

Pipe ovalizations were also introduced into all models to simulate actual diameter imperfections, and to

provide a trigger for buckling failure mode. This was done during model generation by pre-defining

ovalities at various locations in the pipe model.

Bending case

A pipe bend portion of the model was developed to investigate local buckling under pure moment

loading. Due to the symmetry in the geometry and loading conditions, only one half of the pipe was

modeled, in order to reduce the required computational effort. The pipe mesh was categorized into four

regions

Two refined mesh areas located over a length of one pipe diameter on each side of the mid-

point of the pipe to improve the solution convergence (location of elevated bending strains and

subsequent buckle formation)

Two coarse mesh areas at each end to reduce computational effort.

Clamped-end boundaries were imposed on each end of the pipe model to simulate actual test

conditions (fully welded, thick end plate). Under these assumptions, the end planes (nodes on the face)

of both ends of the pipe were constrained to remain plane during bending. Loading was applied by

controlled rotation of the pipe ends.

In terms of material properties, the axial compressive stress-strain response tends to be different from

the axial tensile behavior for UOE pipeline steels. To accurately capture this difference under bending

conditions, the upper (compressive) and lower (tension) halves of the pipe were modeled with separate

axial material properties (derived from independent axial tension and compression coupon tests).

In general, the local compressive strains along the outer length of a pipe undergoing bending will not be

uniform due to formation of a buckle profile. In order to specify the critical value at maximum moment

for an average strain, four methods were selected based on available model data and equivalence to

existing experimental methods.

Collapse case

The same model developed for the bending case was used to predict critical buckling under external

hydrostatic pressure. This included the use of shell type elements and the same mesh configuration. In

the analyses, a uniform external pressure load was incrementally applied to all exterior shell element

faces. Radially constrained boundary conditions were also imposed on the nodes at each end of the pipe

to simulate actual test conditions (plug at each end). In contrast to the pipe bend analysis, only a single

stress-strain curve (based on compressive hoop coupon data) was used to model the material behavior

of the entire pipe.

Bending case validation

The pipe bend finite element model was validated using full-scale and materials data obtained from the

Blue Stream test program, both for “as received” (AR) and “heat treated” (HT) pipe samples.

Geometrical parameters were taken from the Blue Stream test specimens and used in the model

validation runs. Initial ovalities based on average and maximum measurements were also assigned to

the model. The data distribution reflects the relative variation in ovality measured along the length of

the Blue Stream test specimens.

All of finite element models included analysis input files generated using parametric generator for pipe type models that

allows for variation of pipe geometry (including imperfections), material properties, mesh densities, boundary conditions,

and applied loads.

Axial tension and compression engineering stress-strain data used in the model validation were based

on curves fit to experimental coupon test results. As pointed out previously, separate compression and

tension curves were assigned to the upper and lower pipe sections, respectively, in order to improve

model accuracy.

In the validation process, a number of analyses were performed to simulate the Blue Stream test results

(base case analyses), and to investigate the effects of average strain definition, gauge length, and pipe

geometry. These analyses, comparisons and results were:

The progressive deformation during pipe bending for the AR pipe bend showed the

development of plastic strain localization at the center of the specimen

A comparison between the resulting local and average axial strain distributions for two nominal

strain levels indicated that at the lower strain level the distribution of local strain is relatively

uniform, at the critical value (peak moment) a strain gradient is observed over the length of the

specimen with localization occurring in the middle, the end effects are quite small due to

specimen constraint and were observed at both strain levels

The resulting moment-strain response for the AR pipe base case analysis found the calculated

critical (axial) strain slightly higher than that determined from the Blue Stream experiments

The effect of chosen strain definition and gauge length on the critical bending strain for the AR

pipe base case analysis, using the four methods for calculating average strain, gave similar

results

The critical strain value is somewhat sensitive to gauge length for a variety of OD/t ratios

The finite element results are seen to compare favorably with existing analytical solutions and

available experimental data taken from the literature. For pipe under bending, heat treatment

results in only a slight increase in critical bending strain capacity.

Collapse case validation

Similar to the pipe bending analysis, the plain pipe collapse model was also validated using full-scale and

materials data obtained from the Blue Stream test program, both for “as received” (AR) and “heat

treated” (HT) pipe samples. Pipe geometry and ovalities measurements taken from the Blue Stream

collapse specimens were used in the validation analyses. Initial ovalities based on average and maximum

measurements were also assigned to the model at different reference points. Hoop compression stress-

strain data was used in the model, and was based on the average of best fit curves from both ID and OD

coupon specimens, respectively. To validate the pipe collapse model, comparison was made to full-scale

results from the Blue Stream test program which demonstrated a very good correlation between the

model predictions and the experimental results.

In addition to the base case, further analyses were run for a number of alternate OD/t ratios ranging

from 15 to 35. Similar to the pipe bend validation, the OD/t ratio was adjusted by altering the assumed

wall thickness of the pipe. The finite element results have compared favorably with available

experimental data taken from the literature.

The beneficial effect of pipe heat treatment for collapse has resulted in a significant increase in critical

pressure (at least 10% for an OD/t ratio of 15). The greatest benefit, however, is observed only at lower

OD/t ratios (thick-wall pipe). This can be attributed to the dominance of plastic behaviour in the buckling

response as the wall thickness increases (for a fixed diameter). At higher OD/t ratios, buckling is elastic

and unaffected by changes in material yield strength.

Pre-bent effect on collapse

Finite element analyses were also performed to simulate recent collapse tests conducted on pre-bent

and straight UOE pipe samples for both “as received” (AR) and “heat treated” (HT) conditions. The intent

of these tests was to demonstrate that there was no detrimental effect on collapse capacity due to

imposed bending as a result of the overbend process. In the pre-bend pipe tests, specimens were bent

up to a nominal strain value of 1%, unloaded, then collapse tested under external pressure only.

To address the pre-bend effect on collapse, a simplified modeling approach was used whereby the increased ovalities and

modified stress-strain properties in hoop compression due to the pre-bend were input directly into the existing plain pipe

collapse model (the physical curvature in the pipe was ignored).

To address this loading case, a simplified modeling approach was used whereby the increased ovalities

and modified stress-strain properties in hoop compression due to the pre-bend were input directly into

the existing plain pipe collapse model (the physical curvature in the pipe was ignored).

A comparison between the predicted and experimental collapse pressures for both pre-bent and

straight AR and HT pipes indicates that the model does a reasonable job of predicting the collapse

pressure for both pipe conditions. It is also clear that the effect of moderate pre-bend (1%) on critical

collapse pressure is relatively small.

While the pre-bend cycle results in an increased ovality in the pipe, this detrimental effect is offset by a

corresponding strengthening due to strain hardening. As a result, the net effect on collapse is relatively

small. For the AR pipe samples, there was a slight increase in collapse pressure when the pipe was pre-

bent. Conversely, for the HT pipe, the opposite trend was observed. This latter decrease in collapse

pressure can be attributed to two effects: the larger ovality that resulted from the pre-bend cycle and

the limited strengthening capacity available in the HT pipe (the HT pipe thermal treatment increased the

hoop compressive strength, offering less availability for cold working increases due to the pre-bend).

Similar to previous experimental studies on thermally aged UOE pipe, the beneficial effect of heat

treatment was demonstrated in the pre-bend analysis. The collapse pressure for the pre-bent heat

treated (HT) pipe is approximately 8-9% higher than that for the as received (AR) pipe, based on both

the analytical and experimental results. This increase, however, is lower than that observed for un-bent

pipe (approximately 15-20% based on analysis and experiments).

This unique case of an initial permanent bend demonstrated that the influence on the collapse strength

of a pipeline was minimal resulting from an increase in hoop compressive strength (increasing collapse

strength), and an increase in ovality (reducing collapse strength). This directly suggests that excessive

bending in the overbend will not significantly influence collapse strength.

Future work includes advancing the model validation to the case of active bending while under external

pressure. This condition exists at the sagbend region of a pipeline during pipelay and, in many cases, will

govern overall pipeline wall thickness design.

Acknowledgments

The authors would like to acknowledge the support of this program by Medgaz SA and the technical

contributions of Medgaz personnel throughout the model development phase.

Editor’s Note: This a summary of the OMAE2006-92173 paper presented at the 2006 OMAE conference

in Hamburg, Germany, June 4-9, 2006

11/01/2006

http://www.offshore-mag.com/articles/print/volume-66/issue-11/pipeline-transportation/

understanding-pipeline-buckling-in-deepwater-applications.html

Wet welding critical to

structural maintenanceState-of-the-art work proving product

C.E. Grubbs, Thomas J. Reynolds

Global Divers & Contractors

Offshore structures in place worldwide are an integral part of the oil and gas industry'

infrastructure. These offshore structures provide strategic support for the exploration,

production, and transportation of oil and gas. Maintaining the structures is a challenging task.

Maintenance divisions of offshore operating companies must properly protect

and repair the vital structures after they have sustained structural damage

due to accidents during and after installation, fatigue, corrosion, boat

collisions, and acts of nature.

Global Divers & Contractors and the Center for Welding and Joining Research

at the Colorado School of Mines (CSM) lead a consortium of major offshore oil

and gas companies and the Department of Interior's Minerals Management

Service in the development of improved underwater welding techniques and

welding electrodes for use on structural steels used in the construction of

offshore structures.

Working with the Edison Welding Institute, Global's research also includes

the development of underwater wet welding procedures on pipeline steels

for the Pipeline Research Council (PRC) International. This work is done at

Global's Research and Development Center in New Iberia, Louisiana. The

Center includes hyperbaric facilities capable of simulating wet or dry welding

environments for water depths down to 366 meters.

As the number of offshore structures grows, and those in existence continue

to be exposed to fatigue, corrosion and accidental damage, the need for

underwater structural repairs increases. This, of course, emphasizes the

need for continuing efforts to upgrade underwater repair technology.

Causes, with typical examples, of underwater damage to offshore structures

include the following:

Corrosion: Depleted sacrificial anodes, intermittent operation of impressed current

systems, inadequate design of cathodic protection systems and improper grounding of

barge/boat mounted welding machines when welding on offshore structures.

Skirt pile installation: Damage frequently occurs when attempts to "stab" skirt piles into

bell-guides are made without a diver or video camera to provide underwater vision.

Dropped objects: Objects dropped overboard have included skirt piles, bundles of pipe

and other items of material and equipment during off-loading, boat landings during

installation, and pile driving adapter caps.

Boat impact: Collisions involving boats and structures are not uncommon and repeated

impact with through the water line members, boat landings, and fendering systems have

resulted in gross structural damage.

Acts of nature: Hurricane Andrew did extensive damage to Gulf of Mexico structures and

the dragging of ship's anchors displaced several subsea pipelines. Infrequent mud slides

have also damaged structures and pipelines in the Gulf.

Design engineering: While infrequent, design errors and unanticipated loads have

resulted in severe damage to offshore structures.

Repair options

Viable repair methods include mechanical clamps, with and without grout, wet welding, and dry

hyperbaric welding.

Hundreds of wet welded structural repairs have been made by welder/divers

qualified in accordance with the requirements of the ANSI/AWS Specification

for Underwater Welding (AWS D3.6), using qualified welding procedures, with

no known failures.

However, prior to developments during the Global/CSM Joint Industry

Underwater Welding Development Program (JIP), wet welds were not

attempted on base metals with carbon equivalents (CE) greater than 0.40 wt

pct (CE = C + Mn/6 + (Cr + Mo + V)/5 + (Cu + Ni)/15) due to hydrogen-

induced underbead cracking in the heat affected zone (HAZ) of the base

metal.

Underwater dry hyperbaric welds, qualified in accordance with requirements

of AWS D3.6, have mechanical properties equal to similar welds made above

water. However, under some conditions, installation of a dry weld chamber

can impose unacceptable loads on the structure. For example, a chamber

installed on structural members near the splash zone can be subjected to

excessive loads imposed by prevailing ground swells and wave action.

Transfer of loads to structural members can cause failure of the members.

Wet versus dry welds

Wet welding is done at ambient pressure with the welder/diver in the water without any

mechanical barrier between the water and the welding arc. Simplicity of the process

makes it possible to weld on even the most geometrically complex node sections. While

wet welding procedures have been qualified, and used for underwater repairs, down to

100 meters, further development of electrodes and welding processes will be required if

satisfactory wet welded structural repairs are to be made much deeper than that depth.

Dry hyperbaric welding is done at ambient pressure in a custom built

chamber from which the water has been displaced with air or other gas

mixture, depending on water depth. Dry welds, when qualified in accordance

with the requirements of AWS D3.6 for Class A welds, meet all the

requirement for welds made above water.

Several dry welded pipeline tie-ins have been made down to 220m plus one

subsea tie-in was made at 308 m. Repair costs and time for dry welded

repairs are usually at least double that for wet welded repairs.

AWS D3.6 defines Class A (dry) welds as underwater welds that are intended

to be suitable for applications and design stresses comparable to their

conventional surface counterparts by virtue of specifying comparable

properties and testing requirements. Class O welds are intended to meet

requirements of some other designated code or specification as well as the

AWS D3.6 requirements for Class A welds.

AWS D3.6 defines Class B (wet) welds as underwater welds that are intended

for less critical applications where lower ductility and greater porosity and

other discontinuities can be tolerated, and states that the suitability of Class

B welds for a particular application should be evaluated on a "Fitness for

Purpose" basis.

Welding program

The Global/CSM JIP program started in 1993. Phase I of the program was completed in 1995.

Phase II, with the objective of increasing the depth at which code quality (AWS

"Specification for Underwater Welding" D3.6) welds can be made, is ongoing.

Objectives of Phase I of the program were to improve the properties of wet

welds to the highest practical levels, and to determine what those properties

are so they may be used as fundamental engineering design principals for

solutions to underwater repair/construction problems where wet welding

versus dry hyperbaric welding, usually results in significant savings in time

and costs.

Areas of expected improvements included increased ductility and toughness

of weldments and the reduction of hardness and elimination of hydrogen

cracking in the HAZ of crack susceptible (CE.40) base metals.

Program work was guided by the Technical Activities Committee (TAC) which

was made up of one member from each of the participating organizations,

Global and CSM. Phase I participants were: Amoco Research Center, Chevron

Research & Technology Company, Shell Offshore Engineering Research

Department, Marathon Oil Company, Mobil Research & Development

Corporation, Exxon Production Research Company, the US Navy, US Offshore

Minerals Management Service (Department of the Interior) and the UK Health

and Safety Executive-Offshore Safety Division.

Global provided management, welding engineering, technicians,

welder/divers, hyperbaric facilities, welding/diving equipment and materials.

CSM provided scientists, a graduate research engineer dedicated to the

program, welding electrode formulations, analytical equipment and technical

reports on their research tasks.

Matrix and base metal

The test Matrix for Phase I of the program included the following tasks:

Refinement of the multiple temper bead (MTB) wet welding technique used for the

prevention of hydrogen cracking and reduction of hardness in the heat affected zones of

crack susceptible base metal.

Selection of optimum welding power source and auxiliary equipment for underwater wet

welding.

Development of improved electrodes through reformulation of flux coatings and selection

of core wires.

Qualify welding procedures for all position wet fillet and groove welds at 1 meter and 10

meters and make groove welds at 1, 10, 20, 30 and 50 meters with the improved

electrodes.

The test matrix for Phase II concludes with 19 mm groove welds made at depths of 21, 43, 61

and 91 meters, with electrodes formulated for welding at those depths.

ASTM A537 Class 1 19-mm steel plate was selected as the program base

metal because of its proven propensity for hydrogen induced cracking, and

excessive hardness, in the heat affected zone, when welded with

conventional wet welding procedures. The carbon equivalent of the A537

material was .462 including .20 wt pct carbon. The specified minimum yield

and tensile strength were 50 ksi and 70 ksi, respectively.

Multiple temper bead

The unique and proprietary multiple temper bead (MTB) wet welding technique involves three

essential variables which were methodically investigated and are described as follows.

Toe-to-toe distance: The distance between toes of primary weld beads that tie in to the

base metal and toes of temper beads is one of the variables that govern temper bead

heat input to the crack susceptible HAZ. During this part of the program, multiple temper

bead welds were made on the A537 material with toe-to-toe distances of 1.59, 2.38,

3.175, and 22.22 mm. Results of microscopic (250x) examinations, and Vickers 10 kg

(VH 10) hardness tests of the heat affected zone were used to determine unacceptable,

acceptable, and optimum toe-to-toe distances.

Time intervals: For the prevention of HAZ hydrogen cracking, it is essential that we know

how long it takes for HAZ hydrogen cracks to develop, such as the maximum allowable

time between deposition of primary weld beads and temper beads. Based on the data

from five experiments using electrodes other that the Program Ex 7 electrode, on the

A537 material, a baseline crack initiation time was determined to be 3-10 minutes.

To determine the maximum acceptable time between deposition of primary and temper beads,

welds were made with the Program Ex 7 electrodes with the time intervals reported below. The

following are time intervals and results based upon microscopic (250 x) examination of the HAZ:

4-10 minutes with 30-second intervals - no cracks.

10-60 minutes with 10-minute intervals - no cracks.

1.0-1.5 hours with 30 minute intervals - no cracks.

2.0-4.0 hours with 30 minute intervals - all specimens had typical HAZ hydrogen-induced

cracks.

For validation of the highly desirable results (1.5 hours with no cracks), additional experiments

were conducted. The Ex 7 electrodes were used to make an untempered in 19 mm by 305 cm)

groove weld on ASTM A516 Gr. 70 (CE .44) material. Previously, when this material was

welded with commercially available wet welded electrodes, HAZ cracks developed within 10

minutes. After burning the third electrode, the welder/diver observed cracks in the HAZ of weld

metal deposited with the first electrode.

When welding with Ex 7 electrodes, the welder saw no cracks, and when the

weld was completed, none were detected with magnetic particle

examination. Later, one of four cross sections showed no cracks when

examined at 250x.

A second weld was made on the same material with the Ex 7 electrodes

utilizing the MTB technique. For this MTB weld, HAZ hydrogen cracking was

eliminated.

Knowing the maximum time interval between deposition of primary weld

beads and temper beads is essential to the selection of the most efficient

sequence for deposition of filler metal.

HAZ hardness reduction

Throughout the many MTB welding experiments, prevention of HAZ hydrogen cracking was

consistently accomplished without any deliberate action to increase temper bead heat

input by increasing welding amperage or reducing travel speed. For the same welds - with

the exception of a very small area (3.175 mm by 4.76 mm) in the HAZ beneath the toes of

cap passes - maximum hardness of the weld metal and HAZ was well below the Vickers

10kg (VH10) specified by AWS D3.6 for Class A (dry) welds.

Because of the high carbon equivalent (.462) and especially the high carbon

content (.20), hardness in the small areas in the HAZ beneath the toes of the

cap passes ranged from 400 to 442. To meet the AWS D3.6 maximum

hardness of 325 for dry welds, a series of welds were made using

progressively increased levels of temper bead heat input in the cap passes.

For these welds, optimum heat input reduced the aforementioned range of

400-442 to 252-300.

Weld comparisons

Table 1 [139,813 bytes] and Table 2 [102,064 bytes] provide a practical comparison of

the mechanical properties of the state-of-the-art welds made during Phase I of the Joint

Industry Underwater Welding Program. Table 1 compares the mechanical properties of

the JIP wet welds with the AWS D3.6 "Underwater Welding Specification" requirements

for Class A (dry) welds.

Table 2 compares the JIP wet welds with the American Petroleum Institute

"Recommended Practice For Planning, Designing and Constructing Fixed

Offshore Platforms - Working Stress Design" (RP-2A-WSD) for welds made

above water.

Mechanical properties reported in Table 3 [153,425 bytes] are the results of

tests performed on welds made by Global Divers in 1984 (prior to JIP), and

are provided as general information reference the variation in mechanical

properties of wet welds as depth increases.

When Phase II of the ongoing research program is completed,

comprehensive mechanical test results will be available for wet welds made

at depths of 10, 21, 43, 61 and 91 meters, plus baseline information

reference pressure/water depth induced changes in the chemistry and

microstructure of wet weld metal deposited from 26 meters to 122 meters.

Figure 1 [23,926 bytes] shows that Charpy V-notch values of the JIP

quenched and tempered wet welds were significantly greater than the AWS

D3.6 requirements for Class A (dry) welds. During a Joint Industry

Underwater Development Welding Program, Sea-Con Services (later acquired

by Global Divers) made a series of wet welds to determine the fatigue

properties of wet weldments and how they compared to welds made above

water (Figure 2 [15,467 bytes]).

Five dry welded and 19 wet welded fatigue specimens were taken from 25.4

mm thick fillet welded T-plates. Wet welds were made at -10 meters.

Specimens were tested in simulated sea water with fully reversible cantilever

axial loads of 20 ksi tension and 20 ksi compression with 28,840 cycles until

the first appearance of macro cracks and 29,635 cycles to failure.

As shown on Figure 2, fatigue properties of the heat affected zone (the area

most vulnerable to fatigue failure) of the wet welds were equal to those of

the welds made above water, and significantly exceeded the minimum

fatigue properties specified by the American Petroleum Institute,

"Recommended Practice for Planning, Designing and Constructing Fixed

Offshore Platforms - Working Stress Design" (RP 2A-WSD).

Other projects

In addition to the welding done during the Joint Industry Underwater Welding Development

Program, the following welding projects executed by Global Divers are indicative of the

state-of-the-art of underwater wet welding. Unless specified otherwise, welds were

qualified in accordance with the requirements of the AWS "Specification for Underwater

Welding".

Wet welding procedures were qualified, and used for the repair of an offshore production

platform, at the record depth of 300 meters. Ferritic (mild steel) welding electrodes were

used on carbon manganese structural steel.

Wet welding procedures were qualified with nickel welding electrodes on high strength,

high carbon equivalent (CE .476 wt pct) steel for repairs to an offshore structure. When

wet welded with ferritic electrodes, base metals with a carbon equivalent of more

than .40 are subject to hydrogen induced cracking in the heat affected zone.

Qualified underwater wet welding procedures on the new micro alloyed high strength

(TMCP) steels used in the fabrication of deep water offshore structures.

Global was first to qualify underwater wet welding procedures on carbon steel with

ferritic welding electrodes in accordance with the requirements of ASME Boiler and

Pressure Vessel Code for Underwater Welding, Section XI, Div. 1, Code Case N-516-1.

Provided proprietary welding procedures, proprietary welding electrodes and technical

consulting services to the repair contractor, plus project oversight for the offshore

platform operator, for the first underwater wet welded structural repair in the North Sea.

During a joint industry wet welding development program, Sea-Con Services (later

acquired by Global Divers) performed a fatigue test on a series of specimens taken from

1-in. thick fillet welded T-plates in simulated seawater with fully reversible cantilever axial

loading (20 ksi tension, 20 ksi compression). The results, shown in Figure 2, significantly

exceeded the American Petroleum Institute RP 2A - WSD requirements for welds made

above water.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.06/01/1998

http://www.offshore-mag.com/articles/print/volume-58/issue-6/news/general-interest/wet-welding-

critical-to-structural-maintenance.html

Deepwater remote welding

technology for pipeline

repair and hot-tappingKjell Edvard Apeland, Jan Olav Berge, Richard Verley - Statoil ASA

Michael Armstrong, Neil Woodward - Isotek Electronics Ltd.

The second paper highlighted from the subsea/flow assurance track addresses flowline and pipelines.

Remotely operated dry hyperbaric welding technology has been further developed in recent years and is

now becoming the basis for offshore applications both in subsea pipeline repair and hot-tapping

technology. This paper outlines the welding technology and the operational systems developed and built

to provide an offshore service.

The Pipeline Repair System pool (PRS pool) is a joint development between Statoil and Hydro to provide

repair and construction support for the large oil and gas pipeline transportation system on and from the

Norwegian Continental Shelf in the North Sea.

The development is funded by a consortium of companies sharing costs in exchange for access to the

equipment. In 1987 Statoil was appointed to manage and operate the system and since then a

continuous development has been undertaken. Currently PRS is the main repair contingency for

approximately 10,000 km of subsea pipelines with dimensions ranging from 8 to 44 in. and water depths

down to 600 m. This coverage is now being extended to water depths of 1,000 m as new pipelines come

onstream.

The PRS is a comprehensive suite of subsea pipeline construction and repair tools, from isolation plugs

and cleaning tools to large manipulation and installation frames, and welding habitat enclosures. The

repair methods range from applying support clamps to weakened sections to cutting away damaged

sections and replacing with new pipe, joining to the old by either mechanical connections or hyperbaric

welding.

The PRS pool has over the last few years also invested in technology for remote hot-tapping into subsea

pipelines, the objective being to provide technology for development projects which the commercial

supplier market does not provide on short notice.

In order to achieve this, new unique equipment and welding technology has been developed and

qualified with the objective to provide a fully remote operated system without the need for diver-

assisted tasks.

Pipeline repair by welded sleeve technique

Traditional hyperbaric welding techniques involve the use of precision machining of the pipe ends and

performing butt welds using the GTAW (gas tungsten arc welding) process. This involves precision

alignment that can be very demanding (particularly on the second end and especially for large-diameter

pipes).

The new approach avoids the need to achieve butt to butt closure and limits the requirement on

precision alignment by threading a sleeve (slightly oversized to the pipe) over one end and drawing it

back over the two pipe ends to be joined and making the welded join between the end of the sleeve and

the pipe using a GMAW (gas metal arc welding) fillet weld. This technique is used on relatively small-

diameter onshore pipelines and is part of the tools of the plumbing trade, but it has not been deployed

subsea for production pipeline repair.

The development described in this paper is intended for use for repair of up to 44-in. pipelines down to

depths in excess of 1,000 m.

Such a method is not covered directly in the existing regulations and codes of practice, although some

work has been performed to establish fitness for purpose assessment criteria for sleeve welds, and as a

result the project has been working in conjunction with Det Norske Veritas to establish criteria that

could eventually form a code of practice.

The authors discuss next the structural design of the welded sleeve against all relevant limit states for

maximum loads that can occur and with a safety margin dictated by the use of appropriate safety

factors.

The relevant limit states are bursting, global yielding (including buckling), local

overstressing/overstraining, unstable fracture (including possible lifetime crack growth) and fatigue. The

relevant load cases are pressure testing (after repair), maximum loading during operation and fatigue

during operation. It is necessary to consider axial loads that are both tensile-dominated (e.g., for

unrestrained pipe segments) and compressive-dominated (e.g., for partially or fully restrained

segments). Generally the design is governed by the tensile-dominated maximum loading case in

operation.

Remote hot-tapping into subsea pipelines

The basic principle of hot-tapping is to establish a new branch pipeline connection to an existing

(mother) pipeline while under full pressure. This involves connecting the branch pipe, including a valve,

to the mother pipeline, usually by means of welding or mechanical clamp connections, cutting a hole in

the pipe wall by a machine attached to the valve, retracting the cutting head, closing the valve, and

disconnecting and recovering the cutting machine. The pipe branch may now be extended by spools and

tied-in to a new pipeline in the usual manner. This strategy has been shown to be very cost-effective

compared to alternative methods, including shutdown and tie-in at ambient pressure.

So far, divers have been used to weld the branch pipe to the mother pipeline and for all installation and

cutting operations.

The primary focus of the remote hot-tap project is the development of a novel design combining the use

of a remotely installed mechanical clamp (the retrofit tee), providing the necessary structural strength

as well as interfaces toward the isolation valve module and the hot-tap cutting tool, and a saddle-

formed “seal weld” made by remotely operated hyperbaric GMA welding inside the branch pipe.

The authors continue to provide a comprehensive overview of the structural design of the hot-tap tee,

the hyperbaric GMAW process, welding qualifications, experimental equipment, procedural

development, and installation of the welded sleeve and hot-tap tee.

Dry hyperbaric GMAW technology has been formally qualified for water depths down to 1,000 m and

demonstrated and verified to a water depth down to 2,500 m.

The offshore systems and welding technology is part of the PRS pool in Norway and is ready for real

applications offshore.

11/01/2006

http://www.offshore-mag.com/articles/print/volume-66/issue-11/dot-technical-preview/deepwater-

remote-welding-technology-for-pipeline-repair-and-hot-tapping.html

ROV-operable pipeline

flushing and piggingFlushing and pigging of subsea flowlines generally requires traditional vessel-based operated pigging and

testing systems that are equipped with large high-pressure pumps and long umbilicals. In deepwater,

these systems become extremely large, heavy, and awkward to handle and to operate.

Cybernetix is developing Sapps, a cost-effective, compact, light weight subsea flowline flushing and

pigging system that is operable by ROV and that does not require a dedicated umbilical to the surface.

Artist's impression of a Sapps system in operation on the seabed.

After the flowline has been laid in an air-filled mode, the Sapps module is installed adjacent to the

pipeline lay-down head, and the flexible connection is made up using a work ROV. The ROV is connected

to the Sapps control module to allow data transmission and commands between the surface and the

seabed through the ROV umbilical.

The Sapps system filters seawater at ambient pressure and feeds it into the air-filled pipeline, thereby

flooding the line and pushing the pig forward. A flow meter and a hydraulically operated flow control

valve ensure a controlled manner of flooding of the pipe, and a backwash system can be activated in the

event of filter blockage.

If seawater has to be treated, the chemicals that are to be injected are pre-mixed on the surface and

stored in elastomer reservoirs inside the Sapps structure. These reservoirs are fitted with an injection

pump that is controlled by an injection flow meter to ensure a correct water/chemicals ratio.

Sapps is equipped with a booster pump to provide additional pressure to complete pigging of the full

length of the line or to send additional pigs through the line. The system is being designed for

deployment by the vessel's crane; alternatively, the system can be connected onto the ROV as a tool-

skid.

The system is designed for high precision remote control and data transmission through the telemetry

of a standard work ROV via a simple interface of the Sapps' PC surface control with the ROV's control

system. In air, the Sapps is expected to weigh 3 tons, and variable buoyancy allows it to be handled by a

work ROV. The depth rating will be 3,000 m, and the frame support allows it to be installed on very soft

seabeds (5 Kpa). Commissioning of an operational system is scheduled for completion in mid-2003.

05/01/2003

http://www.offshore-mag.com/articles/print/volume-63/issue-5/news/rov-operable-pipeline-flushing-

and-pigging.html

Detection system tracks

minutest pipeline leaksCo.L.Mar's Acoustic Leak Detector (ALD) technology has pinpointed defects this year on three subsea

pipelines in a variety of settings.

ALD installed on a work class ROV.

Leaks in pipelines stem from transition of the transported fluid from the internal pressure to the lower

external pressure. The resultant turbulence and sudden expansion of the fluid mass generate acoustic

signals which the ALD processes to extract from the ambient noise to indicate leakage.

The system's main components are an underwater acoustic sensor that acquires data along the pipeline;

a transmission line that relays data to the surface vessel; and PC-based software that evaluates the

acquired signal in real time, and its development along the pipeline track. This signal is converted by the

ALD's receiver to an audible lower frequency. Depending on the application (inspection or monitoring),

different sensors can be deployed by divers, towed fish, ROVs, or lowered vertically over the side of a

surface vessel.

One recent project was on a newly installed pipeline offshore in the Middle East. Co.L.Mar was called

out following the hydrotest reporting a leak of just 0.21 liter/min which divers had been unable to

locate. At the time, according to Managing Director Luigi Barbagelata, the line was filled with water and

colorant.

"We found the leak at our first attempt on a valve flange – this was the smallest leak we had ever dealt

with and proves the effectiveness and sensitivity of our system," he said. "We used an equipment

spread deployed by divers and an ROV."

Another job was in the Indian Ocean, where Co.L.Mar used an ROV configuration to detect a leak in an

umbilical in 200 m (656 ft.) water depth. Leakage was reported during tests following installation of the

umbilical, which at the time was filled with air.

Leak generated by corrosion and its ALD image.

"Even though conditions were not ideal – a combination of air and pressure of just a few bar - we were

still able to find the leak easily," said Barbagelata.

The third job was Co.L.Mar's first-ever assignment in the Americans. The location was a lagoon in very

shallow water (1 m or 3 ¼ ft. deep). To work in this awkward environment, an ALD sensor, similar to that

used with towed fish for tracking purposes, was mounted on the side of a small aluminum vessel with a

very limited draft.

"The leak [the pipeline was water-filled] turned out to be in an area where the pipeline was covered by

over 10 ft. (3 m) of sand," Barbagelata said. "I believe the reason it was buried by so much sand was not

due to backfilling, but the dynamics of the seafloor in that area."

In June, Co.L.Mar was also commissioned to perform monitoring of the status of a subsea pipeline

during a pigging operation.

"The contractor was concerned about potential stress that would be imposed on the pipeline. We

monitored the pipeline using a towed fish continuously over the 10-day campaign, night and day, to

ensure that if there were a leak, we could deal with it. The pigging team was working from the platform,

while our specialists were based on the survey vessel with equipment ready for a repair if a leak were

found."

Over the past two years. Co.L.Mar has been working on a new monitoring system for leak detection on

subsea structures such as christmas trees, manifolds, or valves. Currently a basic prototype version is

undergoing tests in a 6 x 10-m (20 x 33-ft.) indoor tank in 8 m (26 ft.) water depth: the sensor is designed

to give an indication of the presence of a leak and the direction of the leakage.

"It comprises an array of four elements, which have so far given good results in the pool. Our next step

is to repeat and optimize the test in the pool, then perform further tests out at sea with real leak

detection equipment."

11/01/2012

http://www.offshore-mag.com/articles/print/volume-72/issue-11/supplement-italy/detection-system-

tracks-minute-pl-leaks.html

Leak detection system

extended to AUV

inspections

Schematic shows an ALD in action on an offshore pipeline.

Co.L.Mar is developing new applications for its Acoustic Leak Detector (ALD) technology on subsea

pipelines.

Leaks in pipelines are generally caused by the transition of the transported fluid from the internal

pressure to the lower external pressure. The resulting turbulence and sudden expansion of the fluid

mass generate acoustic (ultrasound) signals. The ALD system extracts these signals from the ambient

noise, even when they are very weak. Due to this sensitivity, the system has located leaks down to 0.2

liter/min on an offshore installation.

The system's main components are an underwater acoustic sensor, which acquires data along the

pipeline; a transmission line that relays the data to the surface vessel; a hardware receiver; and PC-

based software that evaluates the acquired signal in real time and its development along the pipeline

track.

Depending on the application, the ambient conditions, and the means available on site, the inspection

equipment may be hand-held by divers to check flanges, deployed in a towfish version, ROV-installed, or

lowered vertically over the side of the surface control/support vessel.

This year Co.L.Mar has used the technology intensively for leak inspections offshore West Africa.

According to managing director Luigi Barbagelata, one assignment involved a pipeline with numerous

flanges.

"Using our equipment, the divers were able to detect which flange was leaking," he said. "Following

tightening of the flange bolts, they reapplied the ALD and verified that a smaller flow was still present,

which meant that further tightening was needed. They could also identify which flange sector was

leaking and which bolts had to be tightened. Without our equipment they would have probably

assumed that the first repair was fine and the leak controlled, but the resultant hydrotest would have

revealed that this was not the case."

In May, Co.L.Mar used the ALD in vertical mode installed for the first time with multi-beam sonar and an

underwater camera. These items were used to verify the positioning of the sensor against the pipeline,

the as-laid chart for which was not accurate. Another project was a leak inspection on a pipeline

offshore Japan operated by a major oil company. Scope of the four-day inspection was to verify the

integrity of the pipeline.

This spring, the company completed the first ALD prototype for installation on an autonomous

underwater vehicle (AUV), with successful trials in a test pool and at sea. The system can be adapted to

different kinds of AUVs to be used for inspecting and checking the integrity of pipelines. "The advantage

of using an AUV for inspecting pipelines is significant, if the vehicle is equipped with a navigation system

for automatically tracking and following the pipeline. In that case there is no need for an acoustic

beacon for navigation of the AUV," Barbagelata said.

The checking capability is applicable to "resident" AUVs, which are deployed to permanently monitor

the conditions of a subsea installation, periodically returning to a subsea base to recharge batteries and

download data.

"The ALD version we have developed at the moment is recording inspection data, but that needs to be

played back to check if there is a leak," he said. "We are now working on software that processes the

data automatically and in real time, and decides autonomously if there is a leak. Once this is

determined, the ALD can interface with the AUV's navigation system, modifying the mission in case of

leak detection. We hope to have this solution ready within six months."

Another ongoing Co.L.Mar development is a monitoring system for detecting leaks on subsea structures

such as christmas trees and manifolds. The company has completed work on an omnidirectional

prototype following extensive tests in an indoor tank. Sea trials are scheduled before the end of the

year, simulating different leaks and pressures. Assuming these are successful, the next step will be to

test the equipment on a real subsea installation. Additionally, the company is working on a more

sophisticated directive sensor.

11/12/2013

http://www.offshore-mag.com/articles/print/volume-73/issue-11/equipment-engineering/leak-

detection-system-extended-to-auv-inspections.html

Subsea pig launcher option

on marginal, deepwater

fieldsMachar deployment rationalizes CAPEX, OPEX costs

Brian Smith

GD Engineering

The rapidly expanding development of deepwater marginal fields using subsea production systems with

long flow lines has led to the need to consider routine pigging operations as an integral part of the

pipeline maintenance program.

To maintain pipeline operating efficiency, wax and liquid removal may be required on a continuous basis

using conventional pigging and/or chemical treatments. Until now, subsea pig launchers have been

technically inflexible and not always reliable. As a result, they have only been installed where there was

no real option, their use being mainly restricted to commissioning operations.

Reliable pigging facilities are critical to the development of marginal fields which use subsea production

systems. Many of these fields are located some distance from the production platform, requiring long

flow lines to be laid. The ability to reliably and economically pig these lines from the subsea installation,

without the need to lay a second line to provide a round trip pigging facility, can result in substantial

overall cost savings when full account is taken of the CAPEX and OPEX costs.

Even when the field layout does allow round trip operations, the problems inherent in pushing solids

and wax to the wellhead before returning it to the platform may eliminate this as an option. Pipeline

insulation costs can impact significantly achievement of a favorable cost trade between CAPEX and OPEX

for dual lines.

Temporary launcher

GD Engineering in Worksop, UK has developed a new subsea pig launching unit which combines

economic and technical flexibility with positive pig launching. Two basic systems have been developed

around the need to match system deployment and operation with the field's operational philosophy.

The recent provision of a subsea multiple pig launching system for BP ETAP is an example of a

temporarily installed launcher deployed subsea only when pigging operations are stipulated. ETAP is the

largest North Sea development for a decade and also one of the most complex. The pig launching

system was originally developed to meet the demanding requirements for continuous pigging of the 22-

mile, 16-in. multiphase flow line from the Machar Field subsea manifold to the Marnock central

processing facilities platform.

The length of this pipeline and the resulting temperature drop from the 120! well temperature meant

that heavy wax deposition could be expected in the pipeline. Process studies indicated that a continuous

program of mechanical pigging would be needed through the field's life in order to maintain maximum

operating efficiency.

Two pigging philosophies were considered:

Round trip, two-line pigging using surface launchers and receivers

A single-line subsea pig launcher then installed on the Machar manifold.

Comparisons between the two systems showed that the single line subsea pig launcher would be most

cost-effective when CAPEX/ OPEX, pigging philosophy and operational factors were fully evaluated. But

the overriding factor was the prohibitive cost of providing an additional flow line to the manifold for the

total round trip pigging distance of 44 miles.

Brown & Root, which performed ETAP development engineering, contracted GD for the launcher

system, which comprises the following elements:

Vertically deployed pig launcher with a capacity for three conventional pigs or a single intelligent

pig

High pressure cap structure to provide positive sealing of the pipeline when the launcher is not

installed

Test stand to allow on-site pressure and function testing

Manifold interface framework to provide terminations for the flowline and pig kicker line

Conventional guide wire deployment system to allow deployment/retrieval of the launcher

using a standard diving support vessel

Pig stop and bypass (PSB) mechanism to provide positive pig launching.

This equipment, operated by a work class ROV using standard API tooling interfaces, was developed by

GD Engineering to meet the continuous demand for reliable pig launching at pre-determined intervals

throughout the field's operating life.

A standard DSV is required for installation of the launcher using guide wire alignment (guide post and

funnel) and heave-compensated lifting equipment. Two hydraulic subsea connectors (16-3/4-in. nominal

size for the pipeline and 5-1/8-in. nominal size for the kicker line) would provide the interface between

launcher and manifold. Installation of the launcher demanded simultaneous makeup of both connectors

to their respective hubs, installed on the manifold structure.

Pig launcher installations are anticipated to be performed four times annually, assuming current

predictions of wax deposition are accurate. On each occasion, three pigs will be deployed, each

removing up to 10 tons of wax.

The pigs' sealing discs form a tight fit with the launcher bore, which provides a positive launch situation

when kicker fluid is introduced behind the pigs. The launcher barrel is long enough to hold three pigs or

a single intelligent pig.

Each pig launcher will require the high pressure cap assembly to be retrieved from the manifold, after

first establishing pipeline sealing integrity. Deployment of the launcher and subsequent fill and

pressurization with manifold product (multiphase hydrocarbon) would follow.

Pig release mechanism

The mechanism developed by GD Engineering for pig release comprises a pressure balanced spool

mounted in a rigid housing. This arrangement provides the integrated function of a pig stop and bypass

(PSB) facility. In operation, the pigs are loaded into the line-sized launcher barrel to predetermined

positions.

The PSB mechanism spools are extended to provide positive retention of the pigs should they slip during

installation of the launcher. The PSB mechanisms are interconnected by pipework to provide a

continuous flow path for the kicker fluid. Connection of this pipework to the manifold kicker line is

achieved through the 5-1/8-in. connector.

Following pressurization with hydrocarbon, flow from the kicker line will pass through the mechanisms

to the front and back of each pig, and between the sealing discs via the pigs' bypass facility, giving a

pressure-balanced situation.

To launch the first pig, the spool of the first PSB mechanism is retracted. As the spool is withdrawn level

with the inside bore of the launcher barrel, the kicker flow passing through the spool is restricted and

full flow is diverted through this mechanism to the adjacent PSB mechanism. A pressure differential is

created that causes the first pig to be pushed along the barrel into the pipeline.

Launching of subsequent pigs follows the same procedure. The PSB mechanism design ensures that the

pig stop is fully retracted before full bypass occurs to prevent the pig from creeping under the stop as

pressure differential increases.

The selected configuration contains a blend of proven subsea technology with new innovations, where

required. By its nature, new technology carries some technical risk until proven in service. To offset this,

detailed test procedures have been introduced to determine, as far as is practical, the likely

performance of such equipment.

The Machar manifold pipelay was completed in March 1997, with site integration testing of the

complete structure last September. GD Engineering manufactured the equipment described, which was

integrated into the manifold structure this February. Pigging operations are due to begin in October.

Deepwater version

For deepwater applications, an alternative to the temporary installation of the launcher uses a pig

cassette system, the pig launcher being permanently located on the subsea manifold. Instead of

deploying the pre-loaded launcher, a lightweight cassette containing the pigs is used to re-load the

subsea launcher with pigs.

Both ROVs or conventional guide wire systems can be used to deploy the cassette, which is loaded into

the launcher through a subsea closure. Sequential release of the pigs is achieved by operation of pig

release latches mounted on the cassette. Kicker flow is directed to each pig in sequence, in a similar

manner to the PSB mechanism on ETAP. This method is especially economic for large diameter pipelines

requiring subsea pigging operations or when continual ROV interventions are required on the manifold

system.

The cassette system incorporates numerous design features to suit different operating philosophies:

A lightweight cassette (reduces installation needs)

No requirement for multi-make/break and aliagnment of connectors for launcher barrel

Deployment by conventional guidance systems or ROV

Horizontal or vertical launcher orientation

Control and operation by ROV or umbilical

Launcher barrel of simple construction - pig release mechanism forms integral part of the

cassette and is recovered to the surface for routine maintenance

Intelligent pig launching and pipeline intervention tool capability with same cassette

replenishment of pigs from subsea storage when availability of surface vessels is limited.

In conclusion, the single line pig launcher can provide a cost-effective solution for marginal and

deepwater applications, whether the requirement is for frequent routine pigging or infrequent

intelligent pig inspections. The system's basic building blocks are designed to provide a standard

interface to other subsea equipment and may allow equipment pooling, leading to further cost savings.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.

04/01/1998

http://www.offshore-mag.com/articles/print/volume-58/issue-4/news/production/subsea-pig-launcher-

option-on-marginal-deepwater-fields.html

Challenges to manufacture

of pipe for deepwater,

corrosive hydrocarbonsRichard Freeman - Corus Tubes Energy

Gas is increasingly important in a historically oil-driven world economy. Its increased value is a driver of

pipeline technology developments. To meet the demand for gas transportation through more onerous

environments, there are factors the pipe and plate makers need to consider to ensure the finished

product meets the standards required especially for sour service and deepwater applications.

One trend driving pipeline demand is the gas production from deepwater fields. Traditionally this gas

would either be flared or re-injected into the well for enhanced recovery. However, operators now are

keen to capture this production and trade it as either liquefied natural gas (LNG) or domestic gas. These

gas-gathering prospects present challenging combinations of deepwater installation, corrosive well

fluids, and difficult shore approach conditions. These all combine for demanding pipe specifications for

manufacturers to meet.

These requirements can be met only with a holistic technical approach from plate procurement to pipe

dispatch. The foundation of this approach is to use the highest quality sour plate, which is delivered

using state-of-the-art primary and secondary steel making, continuous casting, and proper plate rolling

practices. During UOE (U-ing, O-ing, and Expanding) pipe manufacture, the forming process is optimized

so strain is managed to minimize any reduction in sour resistance. For these demanding applications,

low-temperature toughness in the heat affected zone, demanding hardness, and Battelle drop weight

tear test requirements commonly are specified. In combination with forming, welding using optimum

consumables and design parameters ensures the mechanical properties and integrity of the pipe.

Gas-gathering in West Africa

Corus recently completed a series of gas-gathering development projects in West Africa to link fields and

to transport the gas for export as LNG. In total, the company supplied 81,000 metric tons (89,287 tons)

of thick-walled, sour-resistant steel linepipe to three projects

The pipe, ranging from 457 mm (18 in.) to 610 mm (24 in.) in diameter and up to 33.5 mm (1.3 in.) in

wall thickness, is to transport gas in water depths of up to 1,500 m (4,921 ft) over difficult seabed

bathymetry and also with critical shore approach areas. Corus exported the pipe from its Hartlepool 42

in. capacity mill in the UK to West Africa where the project is being completed with first gas scheduled

for 2012.

Thick-walled sour service pipe manufacturing

Gas lines typically are larger diameter and generally constructed from welded linepipe – the most

economical production method. However, for deepwater prospects, the parameters for gas

transmission are restricted by the following:

The offshore lay process and the need for speedy, reliable welding restricts the line chemistry to

strength grades at X65 or below

Seabed stability restricts the diameter of the line that can be installed – larger diameter pipe is

more buoyant and less stable

Larger diameter pipe is more vulnerable to hydrostatic collapse, meaning wall thickness needs

to be increased

Wall thickness also needs to be increased because of corrosion concerns and fatigue life

considerations.

Corus supplied 81,000 metric tons (89,287 short tons) of thick-walled, sour resistant steel linepipe to three projects offshore

West Africa.

These reasons drive a need for thicker pipe wall with higher induced strain during forming, but pipe

which also conforms to international standards such as DNV, ISO, and API. Successful manufacture of

these pipes needs not only an expert understanding of steel and pipe making but also an appreciation of

the service demands.

Challenges of pipe forming

During service, the pipe bore is exposed to a wet, sour (H2S) environment. Atomic hydrogen is

generated at the pipe surface via a cathodic reaction, and enters the steel. Migrating hydrogen atoms

move through the structure, gather and combine with each other at discontinuities, voids, and

susceptible zones in the microstructure to produce molecular hydrogen (H2). The increasing quantity of

H2 at the initiation site creates a high hydrogen pressure, which can be magnified by the shape of the

site, leading to a stress concentration that ultimately “cracks” the microstructure.

Strain compromises sour service phenomena such as hydrogen induced cracking (HIC), and with the

industry looking for more stringent sour resistant ratios, pipe milling influence on these factors need to

be understood.

Total micro-strain from forming could contribute to an increase in the number of available sites for

molecular hydrogen formation throughout the microstructure. Therefore, the effects of compression

and expansion may have to be considered as cumulative. Control of these features within the

microstructure is essential to ensure the pipe’s sour performance is achieved.

The sour resistance of the plate is imparted via the chemistry and microstructure. Most modern

steelmakers agree that to balance the mechanical properties needed with sour resistance, the required

microstructure is a very clean, fine-grained, equiaxed/polygonal, or acicular ferrite structure with limited

volumes of secondary phases such as an artensite/austenite (M/A) phase.

Fine grained equiaxed/acicularferrite structure.

To deliver optimum sour properties in the final pipe, attention needs to be paid to each stage of the

process from steel making to final pipe fabrication. During steel making, the process must be monitored

where the material is treated prior to casting with the correct composition, homogeneity, and

temperature suitable for HIC resistant quality.

Casting is integral to ensuring sufficient quality for plate rolling to HIC grade. This includes controlling

macro-segregation, which occurs as steel transitions from the liquid to the solid phase, achieved through

soft reduction, Statistical Process Control, and Caster configuration processes.

In terms of plate rolling, single-phase austenitic rolling is favored to meet the sour service and drop

weight tear test (DWTT) requirements of a thick wall for offshore projects. However, recent experience

shows that material with a higher proportion of acicular ferrite in the microstructure can be susceptible

to a phenomenon known as “inverse fracture” with associated low shear values, which has not been

seen previously in bainitic/acicular ferrite structures. A program is under way to understand this

behavior and to determine whether DWTT is a viable evaluation of the resistance to long running brittle

fracture for these steels.

Pipe making

While the amount of strain imparted to form the pipe is set by dimensions, there are key parameters to

consider, specifically strain management when forming and welding.

Control of shape and formability is required to ensure a consistent product; poorly controlled forming

leads to variable strain effects within each pipe. The forming in the crimp, U- and O-press, and

subsequent expansion must be accurate and consistent to ensure each pipe produced is representative

of the pipeline as a whole.

Suitable welding consumables are selected to achieve the weld hardness and toughness requirements,

and to deliver good HIC performance across the weld. For toughness, a moderate manganese wire is

used with alloying additions of silicon and molybdenum; titanium and boron also can be used,

depending on the toughness required. The wire is combined with a high-performance, semi-basic and

fully agglomerated flux, which combine to promote formation of acicular ferrite in the weld bead, and

confer good Charpy and crack tip opening displacement (CTOD) toughness at low testing temperatures

while maintaining a stable welding performance.

In addition to the mechanical performance of the weld, a high level of integrity must be maintained

through production. This means low levels of slag entrapment and gas defects, for example, as well as

cracks to ensure a clean seam is presented to the welding machine to avoid gas defects. The weld arc

and flux burden must be sufficiently stable to minimize slag entrapment.

Future trends

The question remains whether these pipelines will continue to be required as technology offers other

methods to transport gas such as FLNG. However, the diversity of the offshore industry almost certainly

means a variety of technologies both old and new will be used in the future.

Deploying an FLNG liquefaction vessel directly to a field similar to an FPSO for oil, may remove the need

in some instances for gas export pipeline projects, but infield subsea connections still will be needed.

Additionally, regassification and liquefaction are being considered for some applications offshore,

opening further pipeline prospects for product transfer from ship to shore. These offshore pipelines are

likely to have demanding specifications, crossing high-risk shore approach areas and shallows.

Additionally, the increasing trend towards deepwater production means the linepipe must counteract

higher concentrations of impurities, driving the need for products to meet severe sour conditions.

03/01/2010

http://www.offshore-mag.com/articles/print/volume-70/issue-3/flowlines-__pipelines/challenges-to-

manufacture-of-pipe-for-deepwater-corrosive-hydrocarbons.html

New pipe-in-pipe design

ensures effective

insulationClose control of bends is key to success in assembly

Derek Bish

Tata Steel

Increasing demand for energy, matched with high commodity prices and advances in technology, are

driving operators to extract whatever reserves remain in the challenging UK continental shelf.

Therefore, the requirement to transfer these multi-phase products from often high-pressure/high-

temperature (HP/HT) wells back onshore is an even more demanding prospect.

Up until now, the common belief in the industry was that pipe-in-pipe systems able to withstand

environmental challenges such as corrosion, structural integrity, and thermal management, would be

too costly and complex to apply to riser systems.

Tata Steel worked closely with supply partners to engineer, procure, and construct these assemblies to

further develop this innovative technology as a cost-effective solution to flow assurance issues.

Need for insulation

HP/HT fields are technically more complex to develop because of the inherently higher energy in the

well fluid and its multi-phase composition. Managing the extreme pressure and operating temperature

must be based and evaluated on criteria such as corrosion, maintaining structural integrity, and thermal

management.

One particular challenge is the management of pipeline shutdown. Less expensive solutions for

managing the insulation of bends such as wet coatings, compromise overall shutdown times due to

reduced thermal efficiency. Solutions, such as "self-draining" spools, present a significant design

challenge that can be mitigated by the inclusion of pipe-in-pipe bends, enabling the same thermal

integrity to be maintained in the whole line.

Tata Steel has previously implemented a solution for pipe-in-pipe bends for a North Sea development.

Since then, new insulation techniques have been developed that give far superior insulation properties.

Risers, spools, and bends

The main challenge with the construction of pipe-in-pipe bends is how to pass the inner flowline bend

into the outer casing pipe. It is important that pipe bends have a straight portion on the end to enable

efficient welding to the next pipe section and this can present the insertion of one bend into the other.

The second construction challenge is efficient insulation. Wrapping or sheathing is simply not practical

here as the insulation would occupy the annulus of the assembly and prevent the integration.

New insulation system

Drawing of the geometry of one pipe into another.

The system developed by Tata Steel overcomes these problems by deploying granular Nanogel

insulation into the annulus of the pipe-in-pipe system. Nanogel is made by first forming a silica gel, then

expelling the water from the silica matrix. The resulting material is granular with trapped nanopores of

air, inhibiting heat transfer by conduction, convection, and radiation (with the inclusion of an opacifier).

The deployment of a novel polymeric bulkhead, cast directly into the annulus, provides a solid barrier to

retain the insulation, which allows for the relative movement of the inner and outer bends. The polymer

is a "syntactic" material, silicone rubber with glass microspheres dispersed through the matrix with high

strength, flexibility, and thermal efficiency. The tangent ends of the inner and outer bends are held

rigidly to ensure that the assembly tolerances achieved at manufacture are retained when the unit is

transferred to the welding contractor for incorporation into the pipeline spool or riser.

In order for the insulation to be effectively deployed and provide the consistent thermal performance,

the annular gap throughout the assembly must be uniform. It is important the manufacturing tolerances

of the pipe and bends are closely controlled.

Steel pipe and bend manufacture

Together with Tata Steel, Eisenbau Krämer (EBK) and the pipe bending plant of Salzgitter Mannesmann

Grobblech (SMGB) have developed a series of controls, including a process and measurement system, to

ensure all bend dimensions are closely controlled and mating bends can be produced, matched, and

paired to ensure the most accurate assembly is produced.

In respect to the process-related thinning in the extrados of the hot induction bends, the wall thickness

for the inner and outer mother pipes was increased accordingly. To match precisely, the mother pipes

have been manufactured with the same ID as the riser pipes.

16-in. clad bends being transferred to the quenching tank after austenitization at SMGB pipe bending mill.

EBK supplied Tata Steel with the mother pipe, which has material properties that allow formation

through hot induction bending. The main material challenges are to ensure the mechanical properties

are suitable after bending. Therefore, SMGB is taking responsibility for the chemical design of the pre-

material. This also involves the consideration of a series of heat treatment and forming processes. EBK

uses a multi-pass welding process and steel plate from premium mills in Europe. The manufacturing

process at EBK generates pipe of the closest dimensional control through a series of cold forming and

sizing operations such as external calibration.

At the SMGB pipe bending plant, the special mother pipes are bent by hot induction bending. Heat is

applied through electrical induction to the mother pipe materials and the pipe is slowly formed to give

the correct geometry. In most pipeline applications the critical dimensions are the positions and

attitudes of the ends of the bends (center-to-end dimension) to maintain the overall geometry of the

pipeline. However, with pipe-in-pipe bends it is important that the bend radius is also accurately

controlled to ensure the two bends can be integrated. The precise dimensions after bending also need

to be maintained following heat treatment. For the inner clad bends, a full-body quench and temper

heat treatment is applied at the SMGB bending mill in order to guarantee homogenized material

properties for the bends, to fulfill mechanical and corrosion requirements.

HP/HT material properties

Additional material complexities have to be overcome. Generally, in HP/HT lines there are challenges

because of corrosion, low temperature toughness, and strength. These parameters require careful

material selection to maintain the balance of properties from the outset through to bend production.

Thermal stresses need to be managed as the loads are shared between inner and outer pipe. In addition,

the insulation can lead to extremes of temperature being retained in the pipe materials during

operation and shutdown that can form challenging conditions for conventional steel products.

Conclusion

HP/HT well environments present some of the most challenging and technologically demanding

conditions for field developments, not least because the properties in each reserve offer significant

challenges in terms of material selection and design.

Tata Steel and its supply partners have expanded capabilities further with the design and creation of

cost-effective insulated pipe-in-pipe bends for risers and spools - an accomplishment previously

considered too difficult.

Pipe-in-pipe bends, while challenging technologically, can lead to simplification of overall pipeline design

and can give better pipeline performance in times of operation and shutdown.

04/11/2013

http://www.offshore-mag.com/articles/print/volume-73/issue-4/engineering-construction-

installation/new-pipe-in-pipe-design-ensures-effective-insulation.html

Innovative engineering

solves subsea pipeline tie-

in challengeCustom hot tapping machine plays pivotal role

Michel Courbat

T.D. Williamson S.A.

Technip was recently contracted by Burullus Gas Co. (Burullus) to tie in an expansion to its existing

subsea West Delta Deep Marine (WDDM) facilities. To accomplish this, it was necessary to tie in a new

36-in. gas trunkline pipeline, which is part of the Phase VII project, to the existing system under pressure

without shutting down production. To perform the tie-in, Technip retained T.D. Williamson S.A. (TDW)

to carry out three subsea hot tap intervention operations.

Two traditional 16-in. hot tap operations would be completed on a 26-in. pipeline, and one innovative

20-in. hot tap on a 36-in. pipeline. To ensure that the hot tap interventions would be successful, it was

necessary to engineer, install and pre-commission two hot tap assemblies, including one capable of

cutting through a blind weld-neck "tappable flange" made of duplex stainless steel on the 36-in. line.

Hot tap machine

In preparation for the operation that would take place in depths to 95 m (311 ft), TDW worked with a

Belgium-based engineering and construction specialist to produce the special hot tap tool known as a

"cutter." This special tool would be used for the 20-in. hot tap and would need the ability to effectively

cut the duplex plate. Since the duplex has a very high mechanical strength – meaning that it has a high

elongation before reaching breaking point and a high level of hardenability – the cutting process

employed must be very rigid and vibration-free while using the TDW Model 936D subsea tapping

machine.

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

Working at TDW's facility in Nivelles, Belgium, a series of engineering, design and preliminary tests was

performed. The first step involved engineering several alternative designs. The first alternative consisted

of using either a proven cutter design; or that proven design updated with various teeth geometry.

However, this option was not pursued because it could not penetrate the duplex stainless steel.

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

A second option involving removable teeth and welded teeth support was considered, but this was

rejected due to its inability to resist vibration.

Ultimately, the design selected for fabrication featured a subsea electro-pump to supply adequate

hydraulic power, a pilot drill with bronze plates to reduce vibration, and a specially manufactured set of

cutters with removable cutting teeth that would be able to penetrate duplex stainless steel without

breaking.

Preliminary trials

After the design was finalized, materials were procured and the prototype was fabricated and made

ready for the first phase of testing: the internal preliminary trials.

A diver prepares for the vertical hot tapping operation.

During a period of eight weeks, the prototype was subjected to rigorous testing associated with a

number of capabilities. The cutter's ability to make deep cuts on a plate of the same type of duplex

stainless steel as the blind weld-neck "tappable flange" on the pipeline was an initial challenge.

A diver carries out the horizontal hot tapping operation.

The team made material and design improvements, ultimately achieving a prototype that could produce

a smooth and satisfactory cutline. In addition, special bronze guides were developed and installed on

the pilot drill to control vibration.

By the end of the four-month trial period, several renditions of the prototype had been used to

complete four tapping operations. Before and after each cutting trial, visual and nondestructive

examinations (NDE) of the cutters and pilot drills were carried out. The final prototype, which featured

dual sets of cutting teeth and the pilot drill with the bronze guides, performed well. As the hot tap

machine would be required to operate at an average pressure of 100 bar, pressure tests were

undertaken to satisfy the requirements of the forthcoming factory acceptance test. The decision was

then made to proceed to the second stage: the official trials.

Official trials

During the official trials three tapping operations were carried out with the custom machine. Two hot

taps were completed on duplex plate, and one cold tap was executed through equal duplex tappable

plate. These tapping operations revealed that the equipment endured the rigorous process, remained

properly aligned and cut the duplex steel plate effectively. These operations took place as part of a

requisite system integration test (SIT), which confirmed the following:

The teeth accurately cut the duplex stainless steel

The pilot drill remained rigid and vibration-free

The design of the cutter was improved by adjusting the teeth support.

It also proved that the tapping machine could be unset in the middle of the cut and reset while reaching

the cut back without causing the tapping machine to be misaligned or moved out of proper position.

With the official trials of the custom hot tap cutter successfully completed, the system received

approvals from Burullus, Technip, and the Burullus Independent Verification Authority to perform the

subsea operation well in advance of the project mobilization. In preparation for the impending

operation, two hot tap machines were produced in order to guarantee 100% back-up of this critical

piece of equipment.

Maintaining gas pressure

For three weeks, TDW worked from Technip's dive support vessel Wellservicer to carry out all three hot

taps. Throughout the process, a prevailing pressure of 100 bar (1,450 psi) was successfully maintained in

the existing gas export system. The innovative hot tap on the duplex tappable flange required just six

days to complete.

In spite of the fact that the hot tap intervention was carried out subsea, making it more complicated to

mobilize and install equipment than when working onshore, the operation was carried out by skilled

divers as intended, with no lost time incidents or production downtime.

Much of the success was attributed to the investment in planning and pre-operational equipment trials

and testing. TDW worked with the Technip and Burullus teams to ensure that the operation would

proceed like clock-work, and that the customized cutting tool would operate effectively on duplex

stainless steel. As a result, the operation provided three tie in points, preparing the way for Technip to

successfully tie-in the new 36-in. gas trunkline for the WDDM Phase VII development.

The author

Michel Courbat is offshore project manager for T.D. Williamson S.A.

11/01/2011

http://www.offshore-mag.com/articles/print/volume-71/issue-11/flowlines-__pipelines/innovative-

engineering-solves-subsea-pipeline-tie-in-challenge.html

Advancing the art of

subsea inspectionShell deploys autonomous underwater vehicles to inspect assets offshore Nigeria

Steve Keedwell

Shell Companies in Nigeria (SCiN)

Shallow-water autonomous underwater vehicles (AUVs) are a valuable tool for asset inspection,

providing benefits for customers, operators, and contractors alike. However, the technology has not

been widely used in the oil and gas industry for asset inspection in shallow water. Working together with

partners, Shell Petroleum Development Co. (SPDC) has achieved several notable firsts in utilizing

shallow-water AUVs offshore Nigeria, including the first survey under the hull of an operational FPSO

vessel.

In a notable first for the industry in West Africa, SPDC, together with partners, has utilized shallow-water

AUVs off the Nigerian coast to survey and inspect subsea assets. These include production systems, such

as three platforms and infield pipelines/flowlines located in the EA field, the Sea Eagle FPSO, as well as

the Offshore Gas Gathering System (OGGS), a 260-km (~160 mi) pipeline spanning the edge of the Niger

Delta.

Due to the challenging near-shore security situation, the deployment of a slow-moving traditional survey

vessel towing sensors was risk-assessed as unacceptable. The assets to be surveyed are located only

some 20-40 km (~12-25 mi) off the Niger Delta coastline, in water depths of 15-40 m (~50-130 ft). OGGS

pipeline and EA field surveys had previously been delayed due to security concerns. In order to ensure

safe offshore operations, regular surveys are required to assess the integrity of subsea assets as well as

evaluate any detailed inspection or maintenance needs that may have emerged.

Shell has a track record of adapting new technology to reduce the HSSE exposure of personnel. So it

came as no surprise that, with a growing need to gather data on the offshore assets, SPDC’s Geomatics

Team was tasked to review alternative survey options. This led to the selection and deployment of the

REMUS 100 AUV operated and managed by Fugro Survey Nigeria Ltd. (FSNL), and supported by Fugro

Survey Africa (Pty) Ltd. (FSAPL).

Fugro Chance Inc., part of the Fugro group, provided two REMUS 100 (Remote Environmental Measuring

Units) systems with associated equipment, with FSNL and FSAPL providing project management and

personnel. SPDC provided the overall project management, in-country logistics and vessels to execute

the work.

The REMUS 100 is a compact, portable, and lightweight (37 kg in air) AUV with an operating depth of

100 m (~330 ft) that can be deployed either from a vessel of opportunity or the quayside. A specially

designed rake is used to launch and recover the AUV. An additional tool adapted for the project was a

“dog leash” to secure the nose of the AUV and to control its entry to the rake. When safely in the rake,

the AUV was manually lifted back onboard the vessel. The AUV can be fitted with a range of sensors and

Inertial Navigation Systems (INS).

Immediate results

To complete the survey operations in Nigeria, two AUVs were operated simultaneously. Inspection

surveys were managed from a main operations vessel that maintained a safe distance from the Niger

Delta coastline. Launch and recovery of the AUVs, carried out by SPDC personnel, was undertaken by a

smaller and faster vessel. Careful planning around logistics, operations, and continual risk assessment

was important to minimize security risks and personnel exposure.

Work scope in the EA field offshore Nigeria.

The ability of the AUV to survey within a few meters of platforms and facilities provided additional value.

First, it avoids the HSSE exposure of the traditional survey method of vessels making close passes to

structures. Second, the time to complete a 600-m (~2,000-ft) survey centred on a structure is reduced,

as the AUV turns significantly faster than a vessel equipped with a standard towed array of sensors

(which requires approximately 30 minutes to turn as opposed to the AUV turning time of 20 seconds).

Also, the time required to mobilize the AUV on a vessel is significantly shorter than to install a survey

package of a side-scan sonar and winch on a traditional vessel. Ultimately, a high-quality dataset was

acquired more quickly, more safely, and at reduced cost.

Pushing boundaries

To monitor the AUV during the mission, an operational practice was established to receive iridium calls

(via satellite) from the AUV, at the control center on board the operations vessel. On receiving the

iridium message from the AUV, the position would be plotted and an update on the estimated time to

complete the survey established.

Mission design example.

As confidence grew in the performance of the REMUS AUV, more complex missions were conducted,

including combined long baseline (LBL) and “dead reckoning” missions. An LBL array uses seabed

transponders placed at known locations on the seabed with baselines that can be several kilometers in

length. The position of each transponder is uploaded into the AUV navigation software and, during the

mission, the AUV navigates by calculating its position relative to each of the transponders, which are set

to transmit when interrogated by the AUV.

The process of “dead reckoning” is used to determine the current position based upon a previously

known position fix, and advancing that position based upon measuring speed over elapsed time and

course deviation. The REMUS AUV is fitted with a range of sensors – Acoustic Doppler Current Profiler

(ADCP), Doppler Velocity Log (DVL), conductivity, temperature and pressure sensors – and uses internal

software to update its position based on the sensor inputs received for navigation. An L1 GPS antenna

with iridium satellite communication, was also installed to send updates on the AUV’s health, and to

derive its sea-surface position. The AUV sensor payload can be modified to include a dual high-

resolution side scan sonar (900 kHz), video camera, and INS.

Using this hybrid approach, the purpose of these missions was to acquire surveys around the structures

and decrease the number of infill pipeline/flowline surveys that would be required on completion of the

platform surveys.

During these missions, there were a number of notable firsts:

Utilization of a shallow water AUV in Nigeria

Multiple platform surveys completed in Nigeria by an AUV

Dual launch and operation of AUVs in Nigeria

Survey under the hull of an operational FPSO in Nigeria by an AUV.

Great potential

The primary challenge was to conduct an important survey in a volatile area with many security

challenges, and to do so in line with Shell’s principle of zero harm to people and the environment. The

use of AUVs enabled SPDC to achieve this goal, but also to leverage technical and commercial benefits

for surveying seabed assets in shelf and near-shore environments.

AUV recovery using the specially designed “rake.”

There is potential for using this method to conduct offshore surveys in high-risk locations. These include

risks of security, unexploded ordnance or mine surveys, requiring a low profile and presence on the

actual site. Further opportunities include environmentally sensitive areas such as coral reefs, where

minimal impact is desired. The possibility of acquiring high-quality datasets with a reduced footprint is in

the early stages. The surveys conducted by SPDC and partners have effectively proven the value of this

method from cost, quality, and safety perspectives.

Other scenarios could include launching multiple AUVs from one survey vessel, which could also conduct

survey operations. For example, during annual pipeline inspection surveys, the vessel could target

pipeline crossings, leaving the AUVs to complete other tasks, and carry out passes close to structures.

AUVs have also been deployed in shallow water by Shell’s Geomatics Team in the Netherlands at the

Ameland platforms.

Recommendations

Opportunities to leverage benefits of shallow-water AUV operations in debris, inspection, and general

seabed surveys, plus operational recommendations, include the following:

AUVs can operate in sea conditions that would preclude standard towed system operations.

Depending on water depth and prevailing weather conditions, a heave effect on side-scan sonar

records could impact data quality. This would need to be assessed on a project-by-project basis.

For deployment of AUVs from smaller vessels, a team of three to four people (depending on

operational hours) is recommended to manage the AUV in the field – party chief, electronics

engineer, and online surveyor (plus one if required). Good pre-planning of logistics (e.g. fueling)

would enable extended field operations. It is recommended that the data be checked in the field

for integrity before transfer onshore for processing. This reduces the number of personnel in the

field, hence HSSE exposure.

Launch and recovery of the AUV needs to be improved. These activities were managed by

modifying the rake to contain two supporting ropes on either side. In addition, the head of the

AUV was snared with a dog catcher on a long pole to bring it under control. The person who

catches the AUV guides it into the rake. AUV recovery time was reduced to less than 15 minutes

in a well-managed and safe manner.

The REMUS AUV GPS antenna would benefit from enhancement from L1 to L1/L2, the ability to

receive differential corrections and for dual operation (currently the iridium and GPS share same

components and do not operate simultaneously).

Installation of a screen visible on the deck for the AUV launch team to view their location.

Ensure that there are sufficient connecting cable lengths for the AUV power and VIP interface to

keep laptops away from the open deck.

Strobe lights are recommended when searching for the AUV in poor light conditions.

Addition of two handles on the exterior casing for lifting the unit.

The use of shallow water AUVs for subsea asset inspection have been positive, and for shelf and

nearshore operators, the AUV is cost-effective. Other possible scenarios could include multiple AUV

launches from one vessel, which could also conduct survey operations, e.g., during annual pipeline

inspection surveys, the vessel could target pipeline crossings, leaving the AUVs to complete other tasks

such as close passes to structures. Under-ice surveying is another possibility, since technology is being

developed to provide the operator with the ability to track, monitor, command, and interact with the

AUV remotely while it is under way, and share information with all interested parties. Two more

possibilities are surveys in high-risk locations (unexploded ordnance/mine surveys) that require a low

profile and surveys in environmentally sensitive areas, such as coral reefs.

04/01/2011

http://www.offshore-mag.com/articles/print/volume-71/issue-4/subsea/advancing-the-art-of-subsea-

inspection.html

High integrity alloys:

Selection issues for

corrosion protectionAlan Robinson

Arc Energy Resources

Consider the problems. Hydrogen sulfide (H2S), dissolved carbon dioxide (CO2) and various chlorides are

all present in the hydrocarbons delivered from subsea fields, and they can be accompanied by high

pressures and high temperatures. And sour service at high temperature is more corrosive, while the

same service at high pressure is more erosive. A combination of the two is a potentially expensive and

hazardous situation that impacts materials selection, in terms of protecting low-cost carbon steels or

manufacturing in high-cost corrosion resistant alloys.

Rotating head.

Corrosion and corrosion prevention cost the subsea oil and gas industry billions of dollars every year, so

the decisions taken are vital. The selection of the materials and the preventative processes used to

extend the operating life of materials is essential to the cost-effective manufacture and safe long-term

operation of equipment such as pipelines and valves, especially in deepwater operations.

When assessing corrosion protection for any production system pipeline, process engineers have

numerous options. The effectiveness of each will vary according to factors such as the aggressiveness of

the product; pressure and temperature; the size and complexity of the system; projected life expectancy

of the well; the development period available; and, perhaps most important, overall budget constraints.

So how can welding engineers help the oil and gas industry to resist these attacks?

Protection, where risk of attack is low and life cycle relatively short, may be as simple as using an

injected inhibitor with conventional high-strength carbon or low-alloy steel. Where greater protection is

needed, corrosion-resistant alloys (CRAs) must be considered. These include austenitic (300 series)

stainless steels, ferritic/martensitic (400 series) stainless steels, duplex stainless steels, or the more

complex high nickel chromium alloys.

Duplex steels and nickel-based alloys, such as alloy 625, are the only materials in general production

which, when welded, achieve suitable levels of protection. However, there are constraints on the use of

these materials in their solid form – namely cost, availability, and the need for very tightly controlled

welding procedures.

Cost is particularly relevant where large quantities of pipe and fittings are needed or when large forgings

or castings are used. Typical examples are wellhead valve systems and pipe bundle bulkheads.

The use of carbon and low-alloy steels clad with a corrosion-resistant alloy is common practice for some

years now. It is a well-proven, economical, and technical alternative to solid alloys. It offers the benefits

of strength and/or availability of base materials combined with corrosion resistance, when applied in

selected areas.

Weld overlay cladding presents the materials engineer with a choice of processes and more flexibility.

An almost infinite range of component shapes and sizes can be protected, with an equally wide range of

base material/cladding alloy alternatives. Weld procedures are normally qualified to ASME IX, as are the

welding operators.

Additional testing to prove conformity with API 6A and NACE MR01-75 also is essential. Selection of the

most appropriate welding process largely depends on factors such as the size and geometry of the clad

area; access to the area to be clad; alloy type; specified clad thickness; chemical composition limits;

welding position; and NDT acceptance standards.

There are many common welding processes but given that the process used must be practical, viable,

and provide the mechanical and chemical conditions to achieve service requirements, economics dictate

that the higher deposition rate processes should prevail.

GTAW (gas tungsten arc welding) provides excellent control and a high quality result. It can be used in

bores as small as 20 mm (0.78-in.), and is suited for components of varied geometry, where the position

of the welding head requires frequent adjustment. These could range from a simple flange that needs to

be clad through the bore and across the sealing face, to a complex valve body with several

interconnecting bores. Utilizing twin wire, hot wire, and multi-head configurations increases the

deposition rates.

Often such equipment also needs cladding to RTJ (ring-type joint flange) grooves. The control available

with GTAW means cladding can follow the profile of the groove rather than filling it completely. This not

only saves time and material during cladding, it also reduces the cost of subsequent finish machining.

Using this process the chemical composition of the welding consumable can be achieved at <2.0 mm

(0.08-in.) from the base material/cladding interface (this can be reduced to <1.0 mm (0.40-in.), in the

case of 300 series stainless steels, where over-alloyed wires are available).

Plasma-transferred arc is another option. The process equipment costs are higher and the process

variables slightly more complex than GTAW, but the increased control available on the arc makes it

more amenable to CNC control. When combined with oscillation, dilution levels down to 3% have been

achieved at 1 mm from the interface.

Arc's development engineers have been working with the new breeds of GMAW (gas metal arc welding)

to improve control of the arc, and the resulting process likely will supplant some current GTAW

applications.

For more open access applications, the electroslag process is economically attractive. It does employ a

large weld pool that requires substantial base metal backing (generally a minimum of 20 mm) in order to

prevent excessive dilution. The deposit thickness is nominally 5 mm (0.2 in.) with the strip widths

discussed here. With 60-mm (2.4-in.) strip, deposition rates of up to 22 kg/hr (48.5 lb/hr) can be

achieved.

To enable the chemical composition of the deposit to match that of the consumable specification within

the first layer (3 mm, or 0.12 in., from the interface), over-alloyed strip and "loaded" metal containing

fluxes are available.

Problems associated with electroslag strip cladding involve the limited availability of strip, which tends

to increase the cost of the material; and the difficulty of feeding the strip when cladding within bores of

pipe. Arc Energy Resources is developing a multi-wire electroslag configuration for pipe cladding. This

should solve both problems and provide a combination of high deposition, excellent profile, and good

quality.

Submerged arc welding using a solid wire consumable, while not as fast, is a useful "halfway house"

between strip cladding and the slower GTAW and pulsed GMAW. The welding heads are not as large as

strip heads, and the consumable delivery method is more flexible. Hence, the capability to use this in

smaller bore diameters. Traditionally larger-diameter (2.4 mm+, or 0.09-in.+) consumables have been

used for this process, again resulting in the need for fairly thick substrates to accept the high heat inputs

and large weld deposits.

11/01/2011

http://www.offshore-mag.com/articles/print/volume-71/issue-11/equipment-__engineering/high-

integrity-alloys-selection-issues-for-corrosion-protection.html

UK pipeline

decommissioning provides

potential for innovationNeed for new lifting, cutting, and trenching techniques

MickBorwell

Oil & Gas UK

Since 1966, 45,000 km (27,962 mi) of pipeline has been installed in the North Sea to transport

hydrocarbons from the UK continental shelf (UKCS) to shore. Of this pipeline, less than 2% has been

decommissioned.

The UK government and industry continue to focus on maximizing recovery of around 15-24 Bboe from

the UKCS, and 2013 brought record investment in new projects. Collaborative work has resulted in fiscal

change and technological advances, but as the basin continues to mature, decommissioning is emerging

as a parallel and growing business opportunity.

Decommissioning expertise is available within the UK supply chain, but without significant activity in this

area, the sector has not been fully tested. To help contractors better understand the opportunities, Oil &

Gas UK has produced several documents.

In its "Decommissioning Insight" published in 2013, the association forecasts that between 2013 and

2022 more than 2,300 km (1,429 mi) of pipeline, infrastructure from 74 fields, more than 70 subsea

projects, and about 130 installations are scheduled for decommissioning at a total forecast expenditure

of £10.4 billion ($17 billion).

Inventory of UKCS pipelines

The pipelines mentioned in the forecast represent a fraction of the extensive network of pipeline

currently installed in the North Sea to transport oil and gas production to host platforms or to shore.

Overall, the UKCS pipeline inventory covers a broad range of equipment designed to accommodate the

transportation of many different fluids under diverse conditions, varying water depths, and different

oceanographic environments.

In many cases, the existence of nearby pipeline infrastructure has led directly to the exploitation of

marginal fields that would otherwise be uneconomic. Such opportunities remain a key factor in the

timing of any pipeline decommissioning. A more detailed description of the different types of pipeline

infrastructure can be found in Oil & Gas UK's 2013 report, "The Decommissioning of Pipelines in the

North Sea Region."

Trunklines represent the major element of subsea infrastructure transporting large quantities of oil and

gas from offshore to onshore receiving facilities and end users across Europe. They account for 18% of

the total number of pipelines and 63% of the total pipeline length in the North Sea inventory.

Such pipelines include some of the longest in the North Sea, often with diameters of more than 30 in.,

and tend to be installed offshore using the S-lay pipelay method from a specialist lay vessel.

The pipeline inventory also includes rigid flowlines, flexible flowlines, umbilicals, and power cables, as

well as associated equipment such as the concrete mattresses used extensively in the UKCS to provide

protection and stability to subsea pipelines, cables, and umbilicals. These flexible mattresses are

typically manufactured by joining different shapes of concrete blocks together with polypropylene or

Kevlar rope. Oil & Gas UK estimates that 35,000-40,000 mattresses have been deployed since operations

began in the North Sea.

While pipelines are integral to field life extension and future development opportunities, some fields in

the UKCS have reached the end of their economic life. Specific parts of the pipeline system naturally

become redundant, and with no potential future use, they are available to be decommissioned.

Seven Navica reeling vessel. (Image reproduced with permission from Subsea 7)

Decommissioning to date

Oil and gas pipeline decommissioning has been taking place in the North Sea since the early 1990s,

when the Crawford field pipelines were decommissioned. Since then, pipeline decommissioning has

continued at a modest rate and only when all potential reuse options for the infrastructure, including

new field developments, have been carefully considered.

Less than 2% of the North Sea pipeline inventory has been decommissioned, and of the pipelines which

have been decommissioned, 80% are less than 16-in. in diameter. Half of the larger diameter pipelines

(16 in. or greater) decommissioned to date were removed; these were all infield pipelines less than 1 km

(0.6 mi) long. The longest large diameter trunkline to be decommissioned so far is the 35-km (21.7-mi)

Piper A to Claymore 30-in. export line, which was decommissioned in situ.

Under current regulations, decommissioning of oil and gas pipelines is considered on a case-by-case

basis using the comparative assessment (CA) process to determine the best option for decommissioning.

The CA process enables the particular diameter, length, and configuration of individual pipelines to be

taken into account when considering decommissioning options against the criteria of safety,

environmental impact, cost, and technical feasibility.

Health and safety is a dominant factor in any CA, with the focus aimed at minimizing the long-term risks

to other users of the sea and the short-term risks to those carrying out decommissioning operations. An

integral part of the process is the environmental impact assessment, which is prepared to support all

pipeline decommissioning plans.

Each decommissioning solution needs to be considered on its individual merits, as pipeline installations

vary widely according to model, location, environment, and maintenance status. It is at the CA stage,

when a number of options are considered, that significant opportunities exist for supply chain

companies to develop innovative technologies for decommissioning pipelines.

Opportunities for innovation

When evaluating a preferred option for decommissioning a pipeline and its associated equipment, the

availability and track record of technology used in previous projects provides the context for the other

key CA criteria of safety, environmental impact, and cost.

Supply chain companies specializing in particular services will have the opportunity to develop

innovative techniques in the key technology areas for pipeline decommissioning, many of which are in

their infancy. These are:

Pipeline cleaning

Trenching, burial, and de-burial

Subsea cutting

Lifting

Reverse installation methods

Mattress removal.

Pipeline cleaning is performed prior to decommissioning and involves the depressurization of a pipeline

and the removal of any hydrocarbons in accordance with the Pipelines Safety Regulations. At this stage

there are opportunities for companies skilled at minimizing the potential contamination of the marine

environment.

The technology for trenching and burial of pipelines during installation is well established, and a number

of contractors offer a range of trenching tools capable of trenching and burying pipelines of various

diameters in all soil types. There is, however, limited experience of existing pipelines, laid on the seabed

surface, being buried specifically for decommissioning in situ.

While there are different methods and types of equipment for cutting pipelines subsea using "cold

cutting" tools such as abrasive water jets, diamond wire cutting, reciprocating cutting, and hydraulic

shears, significant opportunities exist for contractors capable of developing new technologies to

improve these techniques. These might include automated techniques to help reduce the use of divers

in these activities. Lifting sections of infrastructure from the seabed is another area where innovative

thinking is in demand. The "cut and lift" process of decommissioning requires cut sections of pipeline to

be lifted from the seabed to a transportation vessel; supply chain companies providing innovative

cutting techniques could help increase efficiency in this area by reducing the duration of lifting

operations for long lengths of pipeline.

Reverse installation methods encompass both reverse reeling and reverse S-lay techniques. The process

by which rigid or flexible pipelines can be recovered from the seabed by reeling them from the seabed

using a specialist reel vessel is known as "reverse reeling."

For rigid pipe, there are a limited number of specialist reel vessels available from the leading installation

contractors. These vessels are usually engaged in installation activities, but can be adapted to recover

pipelines as part of a decommissioning project. Subsea 7's Seven Navica is one vessel capable of

performing this work.

For larger diameter and concrete coated trunklines, the industry is considering a reversal of the S-lay

installation process by which pipelines could be removed and recovered on to the deck of a specialist S-

lay vessel. However, this has not been done in the North Sea, and more study is needed before the

technique can be considered feasible for decommissioning long distance large diameter pipelines.

As yet, no established technique or technology has been universally adopted for mattress recovery.

Solutions developed by contractors will need to take into account the age and condition of the

mattresses being recovered.

Regional variations

Oil & Gas UK's 2013 "Decommissioning Insight" highlights the contrast between different UKCS basins,

noting that in the central and northern North Sea (CNS and NNS), decommissioning of pipelines and

mattresses is estimated to cost more than £400 million ($655 million) from 2013 to 2022. Over this

period, nearly 40 trunklines (130 km/81 mi), 115 rigid and flexible flowlines (420 km/261 mi), 87

umbilicals (250 km/155 mi), and almost 900 mattresses have been identified for decommissioning in

these basins.

The forecast indicates significant expenditure will take place from 2019 to 2022, suggesting that pipeline

decommissioning will occur toward the latter end of decommissioning programs. The peak in 2019 can

be attributed to at least 10 pipeline decommissioning projects.

While containing a similar number of pipelines to the southern North Sea (SNS), the decommissioning of

rigid and flexible flowlines in the CNS and NNS basins is more expensive, suggesting a greater degree of

complexity in these regions.

Over the same period in the SNS and the Irish Sea, four trunklines (64 km), 116 other pipelines (1,300

km/808 mi), and 21 umbilicals (150 km/93 mi) will be decommissioned at a cost of around £100 million

($164 million). Additionally, 2,100 mattresses have been scheduled for decommissioning.

While these decommissioning activities represent a fraction of the overall market of oil and gas

activities, they are part of a burgeoning sector. By making more information on decommissioning

available, Oil & Gas UK aims to help the industry prepare for decommissioning projects, increase the

efficiency of processes involved, and help ensure that future projects are enabled by an "at the ready"

supply chain.

02/05/2014

http://www.offshore-mag.com/articles/print/volume-74/issue-2/engineering-construction-

installation/uk-pipeline-decommissioning-provides-potential-for-innovation.html

New technologies reduce

pre-commissioning time,

costRange of new products and services aim to help bring facilities online in deeper waters

John Grover

Baker Hughes Process and Pipeline Services

The increasing number of subsea and deepwater developments brings new challenges when there are

no surface connections to the pipeline available for testing and pre-commissioning.

Once constructed/installed, such subsea and deepwater systems still must undergo certain pre-

commissioning and commissioning operations, from initial flooding, gauging and testing, up to final start

up.

While the provision of such services in shallow water and topside-to-topside developments is routine,

the same services at water depths in excess of 1,000 m (approx. 3,300 ft) pose many challenges. These

challenges, and the current/planned technologies to address them, include:

Flooding and pigging subsea pipelines using a remote flooding module (RFM). This enables the

use of available hydrostatic head to flood and pig subsea pipelines while meeting the project

requirements in terms of pig speed, filtration, and chemical treatment.

Use of ROV driven pumping units to complete flooding and pressurization. By using the

hydraulic power from a work class ROV to power a custom built pump skid connected onto the

RFM, all pigging and pipeline testing can be performed subsea.

Use of smart gauge tools (SGT) to gauge pipelines without using aluminum gauge plates. This

allows the gauging of lines with reduced bore PLETs at each end. Also, this gives the ability to

communicate the result of the gauging run through-wall without the need to recover the gauge

plate to surface. This allows testing without pig recovery.

Use of subsea data loggers to record pressures and temperatures during subsea testing, and use

of systems to transmit this data to surface in real-time during the test.

The need for new and improved pre-commissioning technologies is expected to be particularly acute in

the Asia/Pacific market, where there has been a significant increase in deepwater pipeline projects over

the past few years.

Pre-commissioning defined

This flow chart illustrates the pre-commissioning process as typically applied to oil pipelines. The process

for gas lines is similar but involves additional steps prior to handover such as removal of hydrotest water

(dewatering), drying, MEG swabbing, and nitrogen packing (not covered here).

Subsea pipeline flooding

The first subsea pigging units were conceived and developed to overcome problems associated with

flooding and pigging pipelines in deepwater. The latest subsea flooding device is the BHI Remote

Flooding Module, which essentially achieves the same objectives using the latest ROV and subsea

technologies. The RFM is a subsea flow control and regulation system. Once positioned on the seabed

and connected to the pipeline to be flooded or pigged via the HP loading arm, it is “operated” by the

ROV opening the valves to the pipeline. The hydrostatic head of the sea then enters the pipeline through

the RFM because of the differential pressure between the inside of the pipeline, which is at atmospheric

pressure, and the sea.

The pre-commissioning process as typically applied to deepwater oil pipelines.

Seawater enters the RFM via a filter manifold with a specified filtration level, usually between 50 and

200 microns. It passes through a venturi device, which creates a small pressure drop in the onboard

flexible RFM chemical tanks which connect to the water flow pipework. This small differential pressure

induces anti-corrosion chemicals into the water flow at the desired rate. This is pre-set prior to

deployment and adjusted subsea by ROV if necessary.

The chemically treated water is held to a pre-determined rate by a flow regulation system. This

maintains the water flow at the desired speed to match specified or optimum pig speed or flooding

rates. Again, this can be pre-set prior to deployment and because the rate is controlled at a steady level,

the chemical inducement is assured throughout the entire “unassisted” operation. A boost pump is

required to complete final pigging operations due to pressure equalization. This pump is ROV driven,

usually operated when the ROV returns to disconnect and recover the RFM, and in deepwater is

required only for a very short time.

The vessel and ROV can leave the unit in isolation on the seabed during the unassisted operations and

go on to other tasks. There is no need for connection to anything other than the pipeline. Onboard

batteries power data-logging instrumentation which logs flows and chemical rates. Visual readouts allow

the ROV to check status before it leaves and when it returns.

The RFM is positioned on the seabed by the ROV and connected to the pipeline to be flooded via the

innovative rigid loading arm pipe system. The ROV then positions itself on the unit’s roof from where it

can monitor instruments and operate valves to manage the initial stages of the operation and adjust

chemical control valves as needed.

Filtration and chemical treatment specifications are met by onboard facilities. Chemicals are stored in

flexible tanks and introduced by a venturi system regulated by detecting changes in the water flow

through the unit, and automatically adjusts the chemical flow accordingly.

To summarize, the aims of subsea pipeline flooding are to:

Reduce the size of vessel required for pre-commissioning

Negate the need for the vessel to remain on station during the bulk of the operations

Remove the need for an expensive down-line, which is prone to damage

Reduce schedule by increasing possible pig speed

Reduce schedule by use of seabed water removing thermal stabilization for hydrotest

Reduce crew size, equipment spread size, and environmental impact by removal of diesel

engines on pumps, and also to improve safety by taking operations off-deck.

Offshore vessel requirements

RFM loading arm stabbed in.

In the following, we look at the commercial drivers for using such a system. For example, experience

suggests that we need to inject 3,420 lpm (903 gpm) of filtered, treated seawater into a pipeline at a

water depth of 1,000 m. Looking for example at flooding a 8-km (5-mi), 16-in. line at 1,000 m (3,281 ft)

water depth, we can draw the following conclusions:

The down-line option requires almost 10 times the deck space of the RFM option – with the

current shortage of DP vessels and with vessel rates of around $40,000 per day, this can have a

major impact on project cost.

As the RFM floods the line with ambient temperature water, there is no stabilization period –

this could save two days.

The deployment and recovery time for the RFM is far quicker than for a 4-in. down-line.

ROV operating RFM.

As with all new technologies, there are circumstances where the RFM may not be suited to a deepwater

project. These include:

Where one or both ends of the line terminate at a platform/FPSO, as with SCRs

Where a down-line will be deployed for other operations and can conveniently be used for

flooding

Where a large number of pigs are used

Where the line has to be flooded with either fresh water or MEG

Where one on of the line terminates in shallow water.

Subsea pigging equipment

The original subsea pigging unit was designed by pre-commissioning engineers with little input from ROV

and subsea specialists (despite efforts to include them). While the device was successful in achieving its

pre-commissioning objectives, it was not the optimum method of operation for the ROV or deployment

vessel. Unwieldy HP flexible jumper hoses, relatively crude instrumentation, and new ways to use choke

assemblies meant there were areas to improve. With this in mind, recent improvements on the RFM

included:

Holding more chemical than the original subsea unit, allowing less recovery and deployment

cycles and use on longer and larger lines

Using rigid loading arm technology to reduce subsea connection times and to reduce the risk of

HP flexible jumper hose damage

Being extremely ROV friendly – ROV specialists were involved in design to ensure minimum ROV

interface issues.

Other improved features include:

An on-board latching mechanism that allows fast ROV connection for boost pumping

An on-board emergency release system means no risk of an ROV getting stuck on the RFM

Advances in electronics mean more reliable instrumentation

Deployment times are less than one hour in deepwater.

Subsea hydrotesting unit

Recent developments in subsea pumping systems have allowed ROV pump skids to carry out subsea

hydrotesting and leak testing of pipeline systems, thus affording additional savings on vessel size and

cost. When used in with the RFM, significant benefits can be achieved. Naturally, the systems that can

be tested are limited by the maximum performance available from an ROV test pump skid. The BHI SHP

(subsea hydrotesting unit) can produce over 40 lpm (10.5 gpm) pressurization rate from typical project

ROVs.

Subsea hydrotesting unit.

Previously, we examined a down-line system that was needed to flood an 8-km, 16-in. line. Deepwater

lines typically require hydrostatic testing at between 200 barg and 350 barg. A typical 4-in. downline

would not be rated for such pressures (specialized down-lines that can handle such pressures often cost

too much for such applications). Thus, a different down-line must be deployed to pressurize the line.

Deployment times for the down-line are similar to those of the flooding down-line.

The SHP can be deployed with the RFM boost pump; hence there is no delay between completion of

flooding and commencement of pressurization. It has been estimated that this saves a minimum of 24

hours per pipeline.

Smartgauge technology

We need to examine the gauging of the line. All offshore pipeline pre-commissioning operations include

the proving of the internal bore of the line. This is achieved normally by fitting a segmented aluminum

disk to one of the filling pigs, the disk having an outside diameter equal to between 95% and 97% of the

minimum pipeline internal diameter. The principle is that any restriction in the line (buckle, dent, etc.)

would cause one of the aluminum “petals” to bend, indicating a restriction in the line.

Gauge pig prior to launch

The gauge pig is then run as part of the pipeline filling pig train and most specifications require that the

gauge plate be inspected visually prior to the hydrotest. This ensures there is no mechanical damage

within the line that could be affected by the hydrostatic test.

Removing and inspecting the gauge plate is simple onshore (and for pipelines with above surface

terminations); but requires additional work on pipelines terminating subsea and in deepwater. It was for

this application that BJ developed the Smartgauge tool to meet the following needs of deepwater

pipelines. This technology:

Allows lines with restrictions (heavy wall bends, PLET hub restrictions, reduced bore valves) to

be gauged.

Permits gauging data to be reviewed and analyzed. This helps users pinpoint and identify any

restrictions.

Incorporates a system to remotely annunciate the result of the gauging run. This means that the

hydrotest can start immediately upon completion of flooding without the need to recover the

gauge plate to surface for visual inspection.

A standard mechanical gauge plate gives no indication of where damage occurred; this makes

identification of location difficult, time consuming, and expensive. By using the multi-channel

Smartgauge tool with a segmented flexible gauge plate, both the clock position and the location of

multiple defects can be ascertained, reducing the time needed to find the problem.

Future developments

Improving ROV capabilities and advances in electronics will benefit remote flooding and pigging systems.

Use of remote data transmission and signaling will allow associated tasks to be reduced in impact and

cost, or taken completely off of project critical paths.

All future developments will be driven by these common objectives:

Reduce the in-field time required to complete subsea pre-commissioning, hence saving on both

the vessel costs and hire periods for pre-commissioning spreads.

Remove or replace operational processes that have high risk (such as deployment of large

diameter down-lines in deepwater).

Minimize offshore vessel deck space for pre-commissioning equipment, allowing smaller and

cheaper vessels to be used.

6/01/2011

http://www.offshore-mag.com/articles/print/volume-71/issue-6/flowlines-__pipelines/new-

technologies-reduce-pre-commissioning-time-cost.html

Designing large-diameter

pipelines for deepwater

installationUpcoming South Stream project in Black Sea calls for 560 mi of 32-in. pipe in depths to 7,200 ft

Martijn van Driel

Alex Mayants

Intecsea BV

Alexey Serebryakov

OAO Gazprom

Andrey Sergienko

OAO Giprospetsgaz

Gazprom has successfully realized some of the world's largest offshore gas transportation systems, with

pipelines in the 24-in. (61-cm) diameter range traversing water depths of more than 2,100 m (6,889 ft)

with the Blue Stream I and II projects.

Now, with South Stream, project planners are considering the challenges of installing 32-in. (81-cm)

diameter pipeline in depths that will exceed 2,200 m (7,200 ft). The 900-km (560-mi) pipeline will extend

from the Russian coast to a western landfall on either the Bulgarian or Romanian coastline. Some of the

key challenges include:

Water depths exceeding 2,200 m (7,200 ft)

Relatively large pipeline diameter for given water depth

Difficult seabed conditions with steep slopes and geohazards

Potentially aggressive/corrosive subsea environments.

The complexity of an offshore pipeline typically is expressed in terms of the water depth and diameter.

While these are not the only drivers for a project's complexity, this expression does provide a good

insight in the position of a project in relation to the current status of the industry.

While a 24-in. pipeline in 2,150 m (7,053 ft) as installed for Blue Stream in 2003 was a major challenge at

the time, that project did lead to the development of technology that is now considered proven, and

similar projects have been realized in various regions in the world. With projects like South Stream, the

industry is now exploring a new frontier and preparing for the next step.

Seabed conditions

Pipelines across the Black Sea need to traverse a deep abyssal plain bordered by steep and sometimes

rugged continental slopes. While the deepwater of the abyssal plain leads to a high external pressure,

which is important for the wall thickness requirement, the continental slope crossings also can be

challenging, often with high risk of pipeline spanning and geohazards.

Offshore section of the South Stream project.

In deepwater, the current and wave effects are limited, causing little dynamic loading. Allowable

pipeline spans are typically longer than in shallow water and governed by local buckling criteria.

Excessive spans can be corrected either by shoulder shaving, support placements, or combination

thereof; the tooling for both seabed intervention methods has been developed and is available.

Geohazards are defined as features of the natural seabed that threaten the integrity of submarine

pipeline systems. Such features include submarine channels, faulting, unstable slopes, landslides, mud

volcanoes, seabed hydrates, pockmarks, debris, and turbidity flows.

Historically, the risk posed by such features has been eliminated often simply by routing around them.

However, for pipelines crossing a continental slope into deepwater, it becomes less likely that all such

potential hazards can be avoided. Hence, engineering solutions must take into account the underlying

geological and/or sediment movement processes.

Geohazards can lead to significant loads on or displacements of a pipeline. In the Black Sea, the most

relevant geohazards include:

Faults

Unstable slopes resulting in slumps or slides

Mudflows / mass gravity flows

Earthquake or wave induced liquefaction in the shore approach area

Mud volcanoes

Gas-expulsion features.

All of the above features have been identified in the project area, and need to be addressed through

rigorous survey and engineering. Earthquake-induced slope stability and mass gravity flows could pose a

significant risk to the integrity of the pipeline at the Russian continental slope, and a similar situation

exists for the western continental margin. An extensive feasibility survey has been performed to identify

these risks and to develop preliminary route options. To further quantify these risks, it is important to

perform a comprehensive design survey campaign to capture and analyze these geohazards. This can

save a significant amount of time/costs on subsequent detailed surveys, studies, and construction.

It is one of the best-known Black Sea properties: deeper than approximately 150 to 200 m (490 to 656

ft), Black Sea water does not contain oxygen, but does contain dissolved sulfuric hydride. Water mixing

(driven by currents and waves) is needed for the oxygen captured from air and generated by algae at the

sea surface to reach lower layers of the sea. In the Black Sea, there is extremely little vertical water

mixing, resulting in the world's largest stratified water body.

For the Blue Stream project, the environment of the Black Sea was classified as sour (or “H2S

containing”) based on extensive measurement campaigns and supported by historical research data that

showed accelerated corrosion rates in parts of the Black Sea environment. The likely cause of the

corrosion was identified as a combination of H2S and sulphate reducing bacteria (SRB). Detailed water

and soil tests are being performed for the South Stream project to establish the chemistry of the Black

Sea environment over the vertical water column, as well as the top soil to a depth of 4 to 6 m (13 to 19.7

ft) below the seabed surface.

Contrary to normal sour service pipelines in which sour medium is introduced inside of the pipe, the

Black Sea environment may cause H2S exposure to the outer surface of the pipe. This service condition

applies over the system lifetime. It is difficult to quantify, since it depends on highly localized soil

conditions and pipe/soil/water chemical interactions over the complete length and lifetime of the

system. When present, high H2S concentration is typically found at a depth of 2 to 4 m (6.5 to 13 ft)

below the seabed. Its effects on the pipe steel and welds are being investigated.

Since there are no concepts readily available to mitigate an external H2S-containing environment after

pipeline operation, it is essential to correctly assess the associated risks and costs. For South Stream, this

issue is being investigated in detail through an extensive geochemical survey and analysis program, as

well as a detailed material testing and development program.

Hydraulic performance

For a project like South Stream, the investment involved is considerable and the ability to transport

significantly more gas at limited additional cost improves the commercial performance of the project.

Hence, an increase in diameter has significant benefits for the project economics, enabling more gas to

be transported over longer distances. As part of project analysis, planners have examined the typical

relationship between inlet pressure and outside diameter for different throughputs for a 900-km (560-

mi) pipeline. The research showed that a diameter increase from 24 to 32-in. allows twice the volume of

gas to be transported. While the friction loss increases exponentially for smaller diameters, it also

increases with the higher velocities required to transport the same volume through a smaller pipe.

While this figure only relates to a typical pipeline length, the same considerations apply for shorter

distance pipelines, justifying the desire to implement larger diameter pipelines for deep water

application. For inlet pressure requirements up to 30 MPa (4,350 psi), the application of existing and

field proven technologies is available. No technology gap is foreseen.

For pipelines as long as South Stream, the minimum allowable arrival temperature requirement can

become the governing factor rather than the pressure loss. The gas cools when ascending the

continental slope and passing through the buried shore approach section on the receiving end. Good

knowledge of pipeline settlement (and therefore soil conditions) and concrete coating becomes

important to accurately predict the hydraulic performance of the system. In case that the in-situ

sediment at the downstream shore approach is found to be susceptible to frost heave, it would be wise

to consider engineered backfill.

The parameter that strongly influences the system's thermo-hydraulic performance is the embedment

on the continental shelf at the receiving end. Overall, embedment in the soft, often liquid clay of the

Black Sea can easily be 50 to 100% or more of the diameter. Thermo-hydraulic performance is verified

against existing operational information to provide additional certainty; given the importance of pipe

burial, the hydraulic analyses will be revisited after geotechnical survey results are obtained and pipe

burial has been calculated.

Another parameter influencing the receiving temperature is the application of concrete coating.

Concrete coating provides a thermal insulation in comparison to an uncoated pipe. One option being

considered is to continue the deepwater wall thickness up to the receiving landfall, thereby reducing the

extent of concrete coated pipe. While this would most likely result in a higher capex, the overall

throughput capacity could be improved.

Steel grade selection

It is generally practical to apply the highest possible line pipe grade to minimize the wall thickness,

weight, and cost of the pipeline. For deepwater offshore applications, DNV SAWL 450 has been used in

numerous sour and non-sour conditions. DNV SAWL 485 grade has been produced almost exclusively for

non-sour service, although recent developments and trials in sour service conditions have been initiated

for small-diameter pipelines. Nevertheless, additional qualifications for H2S-resistant application are

required to ensure the performance of DNV SAWL 485.

Full-scale collapse test rig.

Installability

The combination of pipeline diameter and maximum water depth for South Stream exceeds that

previously achieved in the worldwide pipeline industry. The first issue to be addressed in terms of

overall construction feasibility is, therefore, the ability to install the selected pipeline dimensions in the

deepwater segment of the route.

Furthermore, the significant route length introduces additional challenges to maximize installation

efficiency. Installation of the pipeline will require extension of the existing global pipelay installation

capacity. In doing so, the success factors and experiences from previous record-setting pipeline projects

such as Blue Stream and Nord Stream must be evaluated and applied where appropriate.

The feasibility of the installation of the deepwater section of the route governs the overall system

construction feasibility. As part of this process, the capabilities of the existing deepwater pipeline

installation vessels are being assessed against the deepwater installation requirements on this project.

The three existing deepwater pipeline installation vessels usually considered suitable for a project like

South Stream are the Saipem S7000, Allseas Solitaire, and HMC Balder. Furthermore, the deepwater

installation capacity will increase in the future if several newbuild vessels are completed on schedule.

These include the Saipem FDS-2 and Castorone; the Allseas Pieter Schelte, and a new vessel being

developed by Hereema Marine Contractors (HMC). In general, it has been concluded that installation is

feasible using the existing deepwater installation vessel fleet. However, the assessment of the existing

three deepwater pipeline installation vessels shows that all three vessels will require some

modifications/upgrades to install the South Stream system safely and efficiently.

Wall thickness

Core to the capability to develop large diameter projects in deepwater is the wall thickness design in

combination with the manufacturability of the linepipe.

Full-scale collapse test pipe.

For the pipe diameter and wall thickness under discussion, only two pipe manufacturing processes are

feasible: JCOE and UOE.

In the JCOE process, the plate is formed to a J-shape using a pressed module, step-by-step at a fixed

width interval. Then using a similar method, the plate is formed to a C-shape until it obtains an O-shape.

The pipe is subjected to cold expansion after tack weld and submerged arc welded at the inside and

outside parts.

The UOE process consists of forming the plate into U-shape and O-shape using a pressed module,

followed by tack weld and longitudinal weld of the pipe. As opposed to the JCOE process, both the U-

shape and O-shape are obtained using one-step forming. Thereafter the pipe is cold expanded to obtain

the required dimension. For both pipe manufacturing methods, the current DNV code formulation

results in a reduction of the compressive strength after the manufacturing process, with 15% compared

with tensile strength.

The wall thickness required for South Stream is at the limit of the leading mills' capability. One limitation

for some mills is the capacity of the pipe-forming process (such as the capacity of the O-press). While

this restriction may be avoided through a considerable investment in upgrade of the mill, the control of

pipe properties in the weld area for such thick-walled pipes remains a major issue (in particular

parameters such as ductility and toughness). For deepwater application, these pipe properties are

critical to the pipe performance. Achieving the desired material parameters for the wall thickness

required using standard calculation methods is on the edge of what can be produced. A small reduction

in wall thickness can result in a major improvement in manufacturability, and thereby drive the actual

feasibility of the project for a specific throughput and OD combination.

For the deepwater section of the pipeline, the design is governed by the local buckling criterion. This

condition occurs during installation at the pipeline sagbend where the pipeline will experience the most

extreme combination of external pressure and bending. In the calculation of the required wall thickness

for this design limit state, the following critical technological advances can be applied:

Recovery of collapse resistance through thermal aging

Tighter dimensional control on line pipe manufacture

Tight control on bending strain during installation

A partly displacement-controlled condition is applied in the design for the sagbend.

The largest contribution to wall thickness optimization is from the recovery of collapse resistance

through thermal aging. Pipe collapse resistance is linked to the pipe hoop compressive strength. Many

studies including small-scale and full-scale tests have been performed in the past 20 years (for example

Oman-India, Blue Stream, and Mardi Gras), evidencing that a significant recovery in collapse strength

can be gained for DNV SAWL 450 steel (in the order of 30%). In fact, test results suggest the collapse

resistance is recovered even beyond the original value.

Using the current DNV F101 formulation, most mills, nowadays, indicate that they are able to produce

pipe with a significantly improved fabrication factor, incorporating strength recovery through thermal

aging. Thermal aging effect is the ability of steel to recover its strength due to strain aging. It is possible

to take advantage of thermal aging through application of external coating, which usually takes place at

the same temperature range as where the thermal aging process occurs.

For a deepwater, large-diameter pipeline such as South Stream, using a thinner wall without

compromising system reliability is desirable not only for the obvious economics in steel saving but also

out of necessity, as blind compliance to the current international design codes would result in a wall

thickness that is beyond manufacturability.

To give the owner, designer, and manufacturer sufficient confidence, Gazprom has commissioned a full

testing program, which is currently ongoing. This testing program includes full scale testing of as-

received and thermally treated pipe joints, subjected to combined loading of external pressure and

bending.

Deepwater repair contingencies

In the past, even though the probability of failure of a properly planned deepwater pipeline is small, the

risk associated has been a concern because of the difficulties in making repairs. While the effort required

remains considerable, current deepwater technology provides the tooling that allows repairs large-

diameter, deepwater pipelines. Even within the region, repair systems are available for the water depth

(Blue Stream) or diameter (Green Stream) under discussion. To combine these into a new application is

relatively straightforward, with little technology gap.

Conclusions

A 24-in. pipeline in 2,150-m water depth or 32-in. pipelines in 1,400-m water depth are accepted by the

offshore industry as proven technologies. The South Stream project is now investigating the feasibility of

using larger diameters (such as 32-in.) in 2,200-m-plus water depths, and its successful construction will

be another step-change for the offshore industry. The use of a larger diameter will provide obvious

benefits for the project economics, allowing a considerably higher throughput; but this requires an

advance application of existing technologies.

For the present installation fleet, the installability of such a pipeline is complex but not governing. This

capability will be further improved if the currently scheduled deepwater installation vessels are

completed on schedule. Still, rigorous design is essential, regardless of the selected diameter.

Key to the success of such projects is the manufacturability of the line pipe with the requisite wall

thickness. The wall thickness required for large-diameter pipelines is on the edge of leading mills'

capabilities. Several technology advances need to be applied to achieve feasibility, and a rigorous

development program is ongoing for successful implementation.

Acknowledgment

Based on a paper presented at the Deep Offshore Technology International Conference and Exhibition

held on Nov. 30-Dec. 2, 2010, in Amsterdam.

08/01/2011

http://www.offshore-mag.com/articles/print/volume-71/issue-8/flowlines-__pipelines/designing-large-

diameter-pipelines-for-deepwater-installation.html

New depth-independent,

high resolution subsea

pipeline inspection tool

releasedMatthew Kennedy - AGR Integrity UK

Nick Terdre - Contributing Editor

External scanning of pipelines traditionally is undertaken by divers who require support vessels. AGR

Group’s Neptune system, however, provides inspection without diver intervention and associated

availability issues and depth limitations.

Neptune combines an external state-of- the-art ultrasound scanner with a small ROV. The system can be

mobilized anywhere in the world to examine and predict the remaining life of subsea tubulars. The

system delivers high-resolution ultrasonic data in real time, which is used to underpin the detailed finite

element analysis (FEA) calculations used in industry-standard, fitness-for-service (FFS) determinations.

AGR’s Neptune pipe inspection tool undergoing deployment.

The neutral buoyant Neptune system, weighing 150 kg (331 lb) in air but neutrally buoyant in water, is

deployed via an inspection class ROV to the work site. The scanner comprises a hydraulically opening

and closing twin collar, 600-mm (23.6-in) wide construction containing a fully automated X-Y scanner.

This clamshell construction is self-aligning to allow rapid installation by the ROV.

Self-centering rams within the clamshell hold the scanner firmly on the pipe, creating a stable platform

for the X-Y probe carriage. The probe carriage has an axial range of 500 mm (20 in.) and a

circumferential movement of over 360º. It is configured to deploy Time of Flight Diffraction (TOFD)

transducers for volumetric weld inspection, and compression wave transducers to perform color graphic

material mapping.

The historic restriction of analogue data transmission has been removed by locating the AGR Technology

Design ultrasonic digital flaw detector on the Neptune scanner. This allows the inspection data to be

digitized and processed at the subsea worksite, then sent through the ROV umbilical to be viewed in real

time on the surface.

Currently, the Neptune system is configured to operate in water depths of up to 1,000 m (3,280 ft), but

this could be extended. The system’s ultimate working or depth range is equivalent to the ROV umbilical

length: some ROVs today operate to a range of 6,000 m (19,685 ft).

The ROV pilot and Neptune operator sit together during operations to ensure optimum operational

interface. The objective of any examination performed with the Neptune system is to obtain high quality

graphical images of parent material, welds, and adjacent HAZ material.

As the probe carriage rasters around the pipe, the data is stored and viewed in real time for both

mapping and weld inspection. In TOFD mode, the two transducers straddle the weld at a pre-set

standoff to allow volumetric imaging of the weld in one pass.

There are a multitude of ROVs in service around the world, hence the importance of being able to

interface mechanically and electronically with any type of inspection class ROV. The size and weight of

the self-contained Neptune system allow deployment from, small supply vessels or fixed offshore

installations to monitor risers and caissons.

The system also can check pipeline areas following subsea impact, anomaly verification and

quantification following IP runs, and to assess potential hot-tap locations. In its current configuration the

double-collar scanner is ideal to examine straight pipe and upstream and downstream of bends.

Close-up of Neptune system.

The examination is performed on production pipelines from the external surface. The cleaner the

surface, the higher quality the resulting images. Thanks to an existing range of cleaning, excavation, and

dredging options, some residing within the AGR group, each proposed inspection site can be addressed

individually to optimize the data quality.

Gaining direct access to the pipeline wall may be difficult if the line is concrete-coated, buried, or rock-

dumped. In such cases, internal inspection techniques may offer a more cost-effective solution, which

AGR again can address via its suite of inspection tools.

Neptune’s current inspection diameter range is 12-18-in. (30-46 cm), with plans to build both smaller

and larger diameter collars deploying the same techniques. There are further plans to use the system’s

scanner as a platform for other techniques such as ACFM, eddy current, and phased array.

AGR embarked on the development of this technology in the mid 1990s aiming to inspect pipelines not

designed for pigging. There are a number of reasons why such services may be required. Many non-

piggable lines have reached the limit of their design life, so their integrity needs to be demonstrated if

they are to remain in operation.

Again, operators in general are giving greater priority to ensuring the integrity of their pipelines, of any

age. Production downtime resulting from loss of a pipeline due to corrosion or a defective weld more

than outweighs the cost of regular inspection. And operators also find themselves facing more stringent

regulations as authorities seek to avoid environmental damage from pipeline leaks.

Crack detection

Demand has grown for internal and external inspection of pipelines and welds the past year. Last fall,

AGR introduced Claycutter X, a technology to excavate the sea bottom and to remove soil from old

pipelines. AGR plans to provide the Neptune Subsea Inspection system and Claycutter X as a package to

combine excavation, examination, and recovering.

Another development is the WeldScan tool, which the AGR PipeTech division says it aims to promote in

the Gulf of Mexico and West Africa. To date the system has been applied only in the Norwegian sector

of the North Sea.

A pipeline inspection train is readied, with AGR’s PipeIntruder, which supplies the motive force, at the front.

Like its predecessor PipeScan, WeldScan is equipped with ultrasonics to measure wall thickness and to

detect weld defects. However, using TOFD takes accuracy to new levels, capable of detecting cracks in

welds of less than a millimeter for both width and depth. In other words, cracks can be identified much

earlier.

This meets the needs of increasing application of exotic and high-grade steels in pipelines and risers to

cope with multiphase flows and corrosive wellstreams. These materials are often difficult to weld, so

regular monitoring of welds is required.

The move into deeper waters also places a premium on reliable integrity monitoring techniques, i.e. for

inspecting steel catenary risers which are exposed to severe loadings.

WeldScan has proved its worth in examining pipelines made of high-grade steel – in this case 13%

chrome – in a number of assignments carried out for an operator in the Norwegian sector.

AGR also has developed a method to transport its inspection tools through the pipeline. This is self-

propelled pig, known as PipeIntruder, incorporates a seal disc with an internal bypass. Water is pushed

through the seal disc by a pump at the front, creating back-pressure to push the tool forward. Pumping

can be reversed, sending the tool backwards.

An odometer wheel tracks PipeIntruder’s position in the pipeline. The tool also has axial and

circumferential motors to position WeldScan alongside a weld with ±1mm (0.04 in.) axial accuracy.

Video cameras monitor this operation. Data from WeldScan is transmitted to the surface via fiber-optic

cable in real time.

The PipeIntruder is available for pipe diameters from 8-30 in. (20.3-76.2 cm). Above 30 in. (76 cm),

electro-hydraulic tractors are available. The pig hauls all combinations of inspection tools, and can travel

up to 10 km (6.2 mi), the maximum range of the umbilical winch.

The string made up of the PipeIntruder and inspection tools is inserted into the pipeline at the host

platform. The tools can be used to inspect other tubular structures such as risers, J-tubes, and loading

lines.

04/01/2008

http://www.offshore-mag.com/articles/2008/04/new-depth-independent-high-resolution-subsea-

pipeline-inspection-tool-released.html

Detection system tracks minutest pipeline leaksCo.L.Mar's Acoustic Leak Detector (ALD) technology has pinpointed defects this year on three subsea

pipelines in a variety of settings.

ALD installed on a work class

ROV.

Leaks in pipelines stem from transition of the transported fluid from the internal pressure to the lower

external pressure. The resultant turbulence and sudden expansion of the fluid mass generate acoustic

signals which the ALD processes to extract from the ambient noise to indicate leakage.

The system's main components are an underwater acoustic sensor that acquires data along the pipeline;

a transmission line that relays data to the surface vessel; and PC-based software that evaluates the

acquired signal in real time, and its development along the pipeline track. This signal is converted by the

ALD's receiver to an audible lower frequency. Depending on the application (inspection or monitoring),

different sensors can be deployed by divers, towed fish, ROVs, or lowered vertically over the side of a

surface vessel.

One recent project was on a newly installed pipeline offshore in the Middle East. Co.L.Mar was called

out following the hydrotest reporting a leak of just 0.21 liter/min which divers had been unable to

locate. At the time, according to Managing Director Luigi Barbagelata, the line was filled with water and

colorant.

"We found the leak at our first attempt on a valve flange – this was the smallest leak we had ever dealt

with and proves the effectiveness and sensitivity of our system," he said. "We used an equipment

spread deployed by divers and an ROV."

Another job was in the Indian Ocean, where Co.L.Mar used an ROV configuration to detect a leak in an

umbilical in 200 m (656 ft.) water depth. Leakage was reported during tests following installation of the

umbilical, which at the time was filled with air.

Leak generated by corrosion and

its ALD image.

"Even though conditions were not ideal – a combination of air and pressure of just a few bar - we were

still able to find the leak easily," said Barbagelata.

The third job was Co.L.Mar's first-ever assignment in the Americans. The location was a lagoon in very

shallow water (1 m or 3 ¼ ft. deep). To work in this awkward environment, an ALD sensor, similar to that

used with towed fish for tracking purposes, was mounted on the side of a small aluminum vessel with a

very limited draft.

"The leak [the pipeline was water-filled] turned out to be in an area where the pipeline was covered by

over 10 ft. (3 m) of sand," Barbagelata said. "I believe the reason it was buried by so much sand was not

due to backfilling, but the dynamics of the seafloor in that area."

In June, Co.L.Mar was also commissioned to perform monitoring of the status of a subsea pipeline

during a pigging operation.

"The contractor was concerned about potential stress that would be imposed on the pipeline. We

monitored the pipeline using a towed fish continuously over the 10-day campaign, night and day, to

ensure that if there were a leak, we could deal with it. The pigging team was working from the platform,

while our specialists were based on the survey vessel with equipment ready for a repair if a leak were

found."

Over the past two years. Co.L.Mar has been working on a new monitoring system for leak detection on

subsea structures such as christmas trees, manifolds, or valves. Currently a basic prototype version is

undergoing tests in a 6 x 10-m (20 x 33-ft.) indoor tank in 8 m (26 ft.) water depth: the sensor is designed

to give an indication of the presence of a leak and the direction of the leakage.

"It comprises an array of four elements, which have so far given good results in the pool. Our next step

is to repeat and optimize the test in the pool, then perform further tests out at sea with real leak

detection equipment."

11/01/2012

http://www.offshore-mag.com/articles/print/volume-72/issue-11/supplement-italy/detection-system-

tracks-minute-pl-leaks.html

Common Types of Pipeline

Flange FacesFlanges provide the necessary connections to link pipelines. Faces are the mating surface of a flange.

Flange faces have to be smooth enough to ensure a tight, leak-free seal for bolted flanges. For the

purpose of this article, we will be focusing on five common types of flange faces:

1. Raised Face (RF)

2. Flat Face (FF)

3. Ring-Type Joint (RTJ)

4. Male-and-Female (M&F)

5. Tongue-and-Groove (T&G)

Raised Face (RF)

The Raised Face type is the most applied flange type, and is easily to identify. It is called raised face

because the gasket is raised 1/16" to 1/4" above the bolt circle face. This face type allows the use of a

wide combination of gasket designs, including flat ring sheet types and metallic composites such as

spiral wound and double jacketed types.

The purpose of a RF flange is to concentrate more pressure on a smaller gasket area and thereby

increase the pressure containment capability of the joint.

Flat Face (FF)

The flat face (full face) flange has a gasket surface in the same plane as the bolting circle face.

Applications using flat face flanges are frequently those in which the mating flange or flanged fitting is

made from a casting.

Flat face flanges are never to be bolted to a raised face flange. When connecting flat face cast iron

flanges to carbon steel flanges, the raised face on the carbon steel flange must be removed, and that a

full face gasket is required. Flat face flanges are used on pump facings or on fiberglass flanges where the

torque of compressing the gasket will damage the flange body and on cast iron flanges sometimes found

on mechanical equipment that can cause complications due to the brittle nature of cast iron. Forged

steel flat face flanges are often found 150# and 300# ratings.

The Flat Face flange has a gasket surface in the same plane as the bolting circle face. Applications using

flat face flanges are frequently those in which the mating flange or flanged fitting is made from a casting.

Ring-Type Joint (RTJ)

The Ring Type Joint flanges are typically used in high pressure (Class 600 and higher rating) and high

temperature services above 800°F (427°C).

RTJ flanges have grooves cut into their faces. An RTJ flange may have a raised face with a ring groove

machined into it. This raised face does not serve as any part of the sealing means. For RTJ flanges that

seal with ring gaskets, the raised faces of the connected and tightened flanges may contact each other.

In this case the compressed gasket will not bear additional load beyond the bolt tension, vibration and

movement cannot further crush the gasket and lessen the connecting tension.

Ring-type joints (RTJ) are considered to be the most efficient flanges for use in pipeline design. Rather

than using a gasket between connecting flanges, RTJ have a deep groove in a ring shared around the

face.

Ring type gaskets must be used on this type of flange. Ring Type Joint gaskets are metallic sealing rings,

suitable for high-pressure and high-temperature applications.

Tongue-and-Groove (T&G)

With this type the flanges must be matched. One flange face has a raised ring (Tongue) machined onto

the flange face while the mating flange has a matching depression (Groove) machined into it s face.′

These facings are commonly found on pump covers and valve bonnets.

Tongue-and-groove facings are standardized in both large and small types. They differ from male-and-

female in that the inside diameters of the tongue-and-groove do not extend into the flange base, thus

retaining the gasket on its inner and outer diameter.

Tongue-and-groove joints also have an advantage in that they are self-aligning and act as a reservoir for

the adhesive. The scarf joint keeps the axis of loading in line with the joint and does not require a major

machining operation.

Male-and-Female (M&F)

This type of flanges also must be matched. One flange face has an area that extends beyond the normal

flange face (Male). The other flange or mating flange has a matching depression (Female) machined into

it s face. Custom male and female facings are commonly found on the heat exchanger shell to channel′

and cover flanges. The female face and the male face are smooth finished. The outer diameter of the

female face acts to locate and retain the gasket.

Advantages:

Better sealing properties, more precise location and exact compression of sealing material, utilization of

other, more suitable sealing and specialized sealing material.

Disadvantages:

Normal raised faced is far more common and ready available both regarding Valves, flanges and sealing

material. Another complexity is that some rigid rules must be applied to the piping design.

Posted: 2014-06-10 10:01:16

Post URL: http://www.landeeflange.com/common-types-of-pipeline-flange-faces.html

Pig Launchers/ Receivers

Jamison Products Pig Launcher/ Receivers offered are a custom engineered design products that meets

customer, environmental and industry standards. The Pig Launcher/ Receiver is built for ease of

operation and longevity of service. With a multiple of option available, Jamison will supply the ultimate

design that readily meets your technical and commercial requirements.

What is a Pig Launcher/Receiver?

Pigging in the maintenance of pipelines refers to the practice of using pipeline inspection gauges or 'pigs'

to perform various operations on a pipeline without stopping the flow of the product in the pipeline.

Pigs get their name from the squealing sound they make while traveling through a pipeline. These

operations include but are not limited to cleaning and inspection of the pipeline. This is accomplished by

inserting the pig into a Pig Launcher - a funnel shaped Y section in the pipeline. The launcher is then

closed and the pressure of the product in the pipeline is used to push it along down the pipe until it

reaches the receiving trap - the 'pig catcher'.

If the pipeline contains butterfly valves, the pipeline cannot be pigged. Ball valves cause no problems

because the inside diameter of the ball can be specified to the same as that of the pipe.

Pigging has been used for many years to clean larger diameter pipelines in the oil industry. Today,

however, the use of smaller diameter pigging systems is now increasing in many continuous and batch

process plants as plant operators search for increased efficiencies.

Pigging can be used for almost any section of the transfer process between, for example, blending,

storage or filling systems. Pigging systems are already installed in industries handling products as diverse

as lubricating oils, paints, chemicals, toiletries, and foodstuffs.

Pigs are used in lube oil or painting blending: they are used to clean the pipes to avoid cross-

contamination, and to empty the pipes into the product tanks (or sometimes to send a component back

to its tank). Usually pigging is done at the beginning and at the end of each batch, but sometimes it is

done in the midst of a batch, e.g. when producing a premix that will be used as an intermediate

component.

Pigs are also used in oil and gas pipelines: they are used to clean the pipes but also there are "smart

pigs" used to measure things like pipe thickness along the pipeline. They usually do not interrupt

production, though some product can be lost when the pig is extracted. They can also be used to

separate different products in a multi-product pipeline.

Why use a Pig Launcher/ Receiver?

A major advantage of piggable systems is the potential resulting product savings. At the end of each

product transfer, it is possible to clear out the entire line contents with the pig, either forwards towards

the receipt point, or backwards to the source tank. There is no requirement for extensive line flushing.

Without the need for line flushing, pigging offers the additional advantage of a much more rapid and

reliable product changeover. Product sampling at the receipt point becomes faster because the

interface between products is very clear, and the old method of checking at intervals, until the product

is on-specification, is considerably shortened.

2/6/2015

http://www.jamisonproducts.com/pipeline-products/pig-launchers-receivers.html

Innovation enhances

deepwater pipeline pre-

commissioning and

inspectionMark J. Slaughter

Weatherford

Deepwater pipeline pre-commissioning and in-line inspections are logistical and technical challenges,

and vessel time is typically a major expense. The Tamar gas field project in the Mediterranean Sea met

these challenges using specialized subsea commissioning technology to mechanically displace and

introduce pipeline fluids, and ultrasonic in-line inspection tools to assure pipeline integrity.

The long-distance, deepwater pipeline project for Noble Energy involved a subsea gas production and

transportation system connecting the Tamar gas field to an offshore receiving and processing platform

linked to the existing Mari-B platform. The system produces gas from five high-flow-rate subsea wells

through separate infield flowlines to a subsea manifold. Dual subsea pipelines transport production from

the subsea manifold approximately 149 km (92.5 mi) to the Tamar offshore receiving and processing

platform. The processed gas goes to the existing Ashdod Onshore Terminal (AOT) for sales into the Israel

Natural Gas Line (INGL).

Weatherford's Pipeline and Specialty Services (P&SS) group was contracted to provide the pipeline pre-

commissioning and inspection, including tieback pipelines, monoethylene glycol (MEG) pipelines, infield

flowlines, gas and condensate injection pipelines, Tamar sales gas export pipeline, and utility pipelines.

Integration of these services through a single contractor was one key to reducing logistical and

scheduling constraints for overall project success.

Infield flowline operations

Challenges and solutions engaged in the project revolved around subsea flooding, testing, and MEG

injection; dewatering, MEG conditioning, and nitrogen purging; and ultrasonic wall measurement base

line inspection.

A key aspect of the pre-commissioning involved flooding, cleaning, gauging, and hydrotesting the 5 x 10-

in. deepwater (1,600 m to 1,800 m/5,248 ft to 5,904 ft) infield flowlines of 4-km to 6-km (2.5-mi to 3.7-

mi) lengths. These operations were performed from the seabed using Weatherford's Denizen subsea

pre-commissioning system.

The Tamar gas field presented many logistical and technical challenges to pre-commissioning and inspection.

Flowline operations were independent of the tieback lines and jumper installation. Schedule flexibility

increased as a result, and the remote subsea operations avoided the use of a large, vessel-based

pumping spread or deepwater downline. Subsea pumps for the flood and hydrotest operations were

driven by high ambient hydrostatic pressure during the pipeline free-flood phase and by ROV hydraulic

power.

The Denizen pigging pump launched the dewatering pig train with slugs of MEG. A custom, high-volume

MEG skid was deployed subsea and connected to the flooding skid to avoid the cost of downline

intervention to inject the MEG.

Pre-launching the pigs allowed dewatering of the 10-in. infield lines via a jumper from the 16-in. tieback

lines. As a result, all dewatering nitrogen injection was performed from the shallow end of the tieback

lines.

Another novel subsea operation used multiple remote subsea data-logging skid packages during hydro-

testing. Typically, the ROV and pumping skid hold station at the end of the pipeline for the full 12- or 24-

hr pressure test. This was unworkable with five pipelines requiring testing and hold periods.

The solution was to deploy multiple independent hydro-test logging skids. The system's pumping skid

has a built-in hydro-test data logging system that displays pipeline pressure, temperature, and pump

flow rate. A high-pressure triplex pump, powered by the ROV's hydraulic system, elevated pipeline

pressure by injecting chemically treated and filtered seawater.

The logging skids were stabbed into the pipeline and the pressure test was conducted through them.

Instead of remaining on station during the hold period, the pump skid was freed to pressurize the next

pipeline.

Twin 16-in. pipelines

Flooding, cleaning, and gauging the twin 147-km (91.3-mi) x 16-in. pipelines was done from a vessel at

the shallow end of the 240-m to 1,700-m (782-ft to 5,576-ft) water depth run. In-line inspection surveys

were conducted during flooding. A caliper tool was pumped to verify minimum bore followed by a

UTMW tool to acquire the wall thickness baseline survey.

The inspection was followed by dewatering operations for all 5 km (3 mi) of the Tamar infield and

tieback pipelines. Pipeline diameter and water depth required a pressure range of 170 to 235 bar (3,465

psi/17 MPa to 3,408 psi/23.5 MPa), which required specialized compression equipment. Weatherford's

Temporary Air Compression Station (TACS) fleet provided sufficient compression power to complete the

dewatering, MEG conditioning, and nitrogen purging in a single pigging operation.

The procedure eliminated additional post-dewatering pigging/purging, and left the pipelines ready to

accept hydrocarbons. MEG batches between pigs in the dewatering train conditioned the post-

dewatering residual water and prevented the formation of hydrates. Additional MEG was included for

pipe wall desalination.

Denizen pumping skid with ROV reduced vessel time for subsea operations.

A novel approach was also used to dewater the 10-in. infield lines via the 16-in. tieback lines without

using a downline or a second vessel. The tieback lines were packed to a higher gas pressure (232

bar/3,365 psi/23.2 MPa) than required for dewatering (170 bar). Later, the nitrogen in from these lines

was directed through a manifold and set of jumpers to drive the pig trains in the 10-in. infield lines.

Because the pig trains were launched earlier, no deepwater downline was required for MEG injection.

Dewatering efficiency was achieved by regulating pig speed using a stab-mounted orifice plate installed

at the discharge end of each 10-in. infield line. Days of vessel time were saved by dewatering all five

infield lines using the pressurized nitrogen contained in the long tieback lines.

UTWM line inspection

The cost of deepwater repair makes inspection accuracy critical to pipeline integrity assessment. An

ultrasonic wall measurement (UTWM) baseline survey was performed on the 16-in. tieback using

Weatherford's latest ultrasonic in-line inspection (ILI) tools.

Ultrasound non-destructive testing has been used for in-line inspection since the 1980s. The technology

measures wall thickness based on ultrasound compression waves directed into the pipe wall. Ultrasonic

transducers positioned 90° to the pipe wall use an impulse-echo mode to transmit an acoustic wave and

to receive return echoes. The echoes represent the locations of the internal and external pipe wall, and

metallurgical anomalies such as laminations. A UTWM baseline inspection identifies and classifies non-

injurious signals such as mid-wall laminations and other mill-related anomalies.

Baseline corrosion survey

Accurate anomaly classification and sizing is valuable when comparing the baseline to future inspection

data. Accuracy also enhances future integrity efforts such as engineering assessments and growth rates.

It is important for deepwater subsea lines where normal onshore non-destructive examination

validation practices are cost prohibitive. A higher level of accuracy is also important when assessing

anomalies, assigning risk, and prioritizing maintenance and expenses.

Advanced ultrasonic inspection tool was used to examine pipeline integrity.

Compared to magnetic flux leakage (MFL) tools, ultrasonic technology results in better sizing accuracy in

determining wall loss and pipe wall thickness. This is because ultrasonic pulse echo physics are a more

direct measurement of wall loss. In some cases, however, MFL is a better solution because it can be

more forgiving of dirt, debris, rough internal pipe surfaces, and waxy liquids. This necessitates a

comprehensive pre-inspection assessment prior to selection of the appropriate technology.

Accurate measurement of wall thickness has a direct influence in calculating the failure pressure of a

corrosion feature. Typical MFL tools do not measure wall thickness but infer it from API pipe

specification, pipeline construction data, and/or estimated variations in the magnetic field. This provides

a relative assessment due to pipeline data inaccuracies or difficultly obtaining data because of asset

ownership transfers, unavailable data, or unrecorded pipeline reroutes and modifications.

In addition, inferred measurements do not consider wall thickness tolerances from the pipe mill. As a

result, an MFL corrosion wall loss depth measurement depends on a relative measurement of the pipe

wall. This decreases the sizing accuracy beyond the normal ILI tool sizing tolerance because, in addition

to tolerances associated with the ILI tool anomaly sizing, there are also tolerances associated with the

actual pipe spool wall thickness from the mill.

Acceptable tolerances from the mill can be as high as ± 10% for pipe wall thicknesses between 5 mm

(0.2 in.) and 15 mm (0.6 in.) in welded pipeline. Tolerances for pipe walls greater than or equal to 15 mm

are ± 15% in welded pipe. These pipe mill tolerances and the high corrosion-anomaly sizing tolerances of

an MFL tool mean the calculated failure pressure from an ILI survey can be significantly over or under as

the result of sizing inaccuracies caused by quantifying depths as a percentage of the assumed wall

thickness.

More accurate corrosion sizing also provides better data to feed an assessment standard such as B31G,

modified B31G, or RSTRENG effective area assessment, the preferred method for determining the

remaining strength of the pipe. Of the three, RSTRENG effective area assessment is the most accurate,

based on actual versus predicted burst pressure tests.

Experience demonstrates the occurrence of echo loss due to adverse pipeline conditions. New sensor

technology in current UTWM devices helps enhance detection and accuracy. API 11636 engineering

tests and field data analysis show improved sensitivity and reduced signal degradation, which is critical

to a successful deepwater subsea baseline survey. The same sensor technology is used for in-line crack

inspection with accurate sizing results that can be used for integrity assessments methodologies such as

API 5797.

16-in. tieback inspection

In the Mediterranean operation, tight scheduling for the subsea launch presented a challenge for the

16-in. UTWM ILI inspections. Normally, there would have been sufficient battery life for the inspection

tool run. However, in this case a delayed activation was needed because of the time needed for a subsea

launch.

The ILI tool first had to be inserted into the pipeline launcher receiver (PLR) onboard the vessel. A vessel

crane moved the launcher with the ILI tool to the pipeline end manifold (PLEM). A hydraulic lock secured

the pipeline end termination (PLET) to the pipeline, and an ROV was used to turn the subsea valves and

launch the pig.

The time-consuming process increased the risk of delays that could drain battery life and cause a failed

run. As a result, a two-hour window was included for unforeseen delays. This safety factor led to

programing a 12-hour delayed activation from the time the tool was inserted into the PLR onboard the

vessel.

12/12/2013

http://www.offshore-mag.com/articles/print/volume-73/issue-12/flowlines-and-pipelines/innovation-

enhances-deepwater-pipeline-pre-commissioning-and-inspection.html

SPIRAL PIPE FOR OFFSHORE APPLICATION

ENERGY SECTOR TO DRIVE

DEMAND FOR SPIRAL

WELDED PIPES AND

TUBES, ACCORDING TO

NEW REPORT BY GLOBAL

INDUSTRY ANALYSTS, INC.Standard

GIA announces the release of a comprehensive global report on the Spiral Welded Pipes and Tubes

markets. Global market for Spiral Welded Pipes and Tubes is projected to reach 24.6 million tons by

2018, driven by economic recovery, level of activity in the energy sector, and intensifying pipeline

construction activity.

Spiral welded pipes market, though encountering overcapacity conditions particularly in North America,

is expected to witness steady growth in the upcoming years driven by the implementation of new

pipeline projects. Investments in oil and gas exploration and production, which are influenced by

prevailing crude oil & gas prices, have a considerable impact on the demand for spiral welded pipes and

tubes. Resurgent world economy and consequent increase in the demand for industrial natural gas is

expected to drive up momentum of the spiral welded pipes market.

Global demand for spiral welded pipes, which are primarily used in the transportation of oil and gas and

in water transportation projects, is closely linked to the investments in the energy sector. The energy

sector makes use of spiral welded pipes with diameters of up to 60” and up to 80 feet in length. Another

factor that is expected to fuel demand for spiral pipes and tubes is new pipeline construction activity

due to the shift of population from traditional centers that would necessitate development of

infrastructure for delivering oil and natural gas to the new locations. Demand for spiral welded pipes is

also expected from the replacement market, as most of the existing pipeline infrastructure, particularly

in developed regions, has reached their end of useful life. Structural applications of spiral welded pipes

are also gaining momentum, specifically with additional activity occurring in port, offshore loading and

infrastructure improvement sectors.

As stated by the new market research report on Spiral Welded Pipes and Tubes, Asia-Pacific represents

the largest market worldwide, driven primarily by increased use in transporting natural gas. Besides

Asia-Pacific, Latin America ranks among the fastest growing regional markets with compounded annual

growth rate ranging between 7.5% and 9.0% over the review period. North American market, on the

other hand, is encountering testing times owing to weak demand and overcapacity conditions.

Oversupply is the major concern for spiral welded pipes market particularly with regard to large

diameter double submerged arc welded or DSAW line pipes, which finds use in transmitting oil, natural

gas liquids, and natural gas to consumers from drilling locations.

Despite the prevailing conditions, potential opportunities are expected primarily from the

implementation of new pipeline projects in the upcoming years, resurgent growth of the US economy,

and increased demand from natural gas exploration operations. Also, overcapacity conditions are

expected to fade away in the coming years, as several megaprojects are set to be taken up across the

world, particularly in regions such as Southeast Asia, Australia, Middle East, Africa, and West Asia.

Replacement of aging infrastructure offers huge potential for pipe manufacturers. The need to replace

old pipelines is particular high in the US and Russia, where pipeline networks were mostly installed

during the 60s and 70s. With the average lifespan of oil and gas transportation pipes ranging between

25 and 30 years, opportunities in the replacement market are huge, particularly for HSAW pipes. In the

US, replacement demand holds enormous potential as a result of the recent enactment of the legislation

that necessitates more inspections to be carried out, which could increase the likelihood of pipeline

replacements. The Act is likely to play a critical role in enabling manufacturers of large diameter line

pipes to survive the tough economic and overcapacity conditions.

Major players profiled in the report include American SpiralWeld Pipe Company LLC, ArcelorMittal SA,

Borusan Mannesmann Boru Sanayi ve Ticaret A.S., Europipe GmbH, EVRAZ North America, JFE Steel

Corporation, Jindal SAW Ltd., Man Industries Ltd., National Pipe Company Ltd., Nippon Steel &

Sumitomo Metal Corporation, PSL Limited, Shengli Oil & Gas Pipe Holdings Limited, Stupp Corporation,

Volzhsky Pipe Plant, UMW Group, and Welspun Corp Ltd.

The research report titled “Spiral Welded Pipes and Tubes: A Global Strategic Business Report”

announced by Global Industry Analysts Inc., provides a comprehensive review of market trends, issues,

drivers, company profiles, mergers, acquisitions and other strategic industry activities. The report

provides market estimates and projections for all major geographic markets including the US, Canada,

Japan, Europe (France, Germany, Italy, UK, Spain, Russia and Rest of Europe), Asia-Pacific (China and

Rest of Asia-Pacific), Middle East, and Latin America.

For more details about this comprehensive market research report, please visit –

http://www.strategyr.com/Spiral_Welded_Pipes_and_Tubes_Market_Report.asp

About Global Industry Analysts, Inc.

Global Industry Analysts, Inc., (GIA) is a leading publisher of off-the-shelf market research. Founded in

1987, the company currently employs over 800 people worldwide. Annually, GIA publishes more than

1300 full-scale research reports and analyzes 40,000+ market and technology trends while monitoring

more than 126,000 Companies worldwide. Serving over 9500 clients in 27 countries, GIA is recognized

today, as one of the world’s largest and reputed market research firms.

Source :

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

prweb10402550.htm

DIRECTIONAL DRILLING:

Horizontal-departure-to-

TVD ratio decline continues

in US GulfDrilling trends in the 1990s, as presented in the April 2000 issue of Offshore,

indicated a majority of extended reach (ERD) wells had horizontal departures in the

range of 10,000-15,000 ft. The second and third highest number of wells were in the

5,000-10,000 ft and 15,000-20,000 ft ranges, respectively.

These Gulf of Mexico trends were pushed up by the 1997 Deep Water

Royalty Relief Act, which encouraged deepwater drilling by designating

geographic areas and allowing deepwater leaseholders to apply for royalty

suspensions in these areas. The total number of directional wells drilled in

1998 was 1,116, out of a total of 1,718 wells drilled. Total well counts for

1999 and 2000 are 1,944 for 1999 and 2,072 for 2000, however total

directional well numbers are not available yet.

Looking at horizontal departure (Dep) and true vertical depth (TVD) of wells

drilled through the mid-1990s, a general "shallowing" trend was evident. The

ratio of Dep and TVD increased over this same time interval. This increase in

the Dep/TVD ratio was due to a continuing increase efficiency of directional

steering systems in horizontal and multi-lateral drilling applications.

However, if a linear progression of future activity into deeper waters is

assumed, a downward trend should develop off to the right of the graph. A

few shallow water wells in the future will continue to be drilled, extending

horizontal wellbores and pushing the Dep/TVD ratio greater than five. Some

experts expect the majority of ERD wells in the early 21st Century will be

drilled with ratios less than two.

The industry is pursuing a number of offshore extended reach projects to be

drilled. Conven-tional steerable drilling assemblies will be the dominant

drilling technique of choice. These conventional assemblies are limiting the

drilling process, instead of contributing to it. However, rotary steerable

technologies are emerging as a solution for this problem, extending reach

capability even further.

Maximum closure

Horizontal and extended reach wells drilled in the gulf are pushing maximum

closure distances to even greater lengths. The US Minerals Management

Service maintains a two-year grace period for operators before releasing

directional well information. These closure distances versus wells are

through 1998, plus early released data of a small number of wells completed

during 1999 and 2000. Operators drilling wells from 1998-2000 with the

greatest maximum closure distances are listed in the table.

An interesting anomaly in maximum inclination can be seen in the 85-100

degree range. The downward trend in the number of wells with increasing

maximum-well-inclination reversed itself and increased slightly over this

inclination range. Also, operators completing wells from 1998-2000 with a

maximum inclination angle of 85 degrees or better are listed in the table.

02/01/2001

http://www.offshore-mag.com/articles/print/volume-61/issue-2/news/directional-drilling-horizontal-departure-to-tvd-ratio-decline-continues-in-us-gulf.html