Corrosion Resistance Alloy for Offshore Pipeline

Fabrication progresses of bi-metal pipe and ancillary supply and control lines into the 44-in. carrier pipe (Fig. 1)

First-gas production from BP Amoco's Bruce Phase II development in the U.K. North Sea flowed in October 1998 through subsea flow lines that represent the largest manufacture of bi-metal-lined pipe to date. In October 1998 through subsea flow lines that represent the largest manufacture of bi-metal-lined pipe to date. Significant cost savings on capital expenditure for production flow lines were achieved by the use of corrosion-resistant alloy (CRA) lined pipe, instead of solid CRA and metallurgically clad pipe options. Presented here are the materials philosophy of the project team and the rationale for selecting bi-metal-lined pipe along with a description of the manufacture, fabrication, and installation of the flow lines. The bi-metal, CRA-lined pipe was supplied by United Pipelines (U.K.) and H Butting (Germany). The flow line was fabricated and the bundle installed by Rockwater Ltd. by controlled depth tow method.

Clad pipe

Use of CRA-clad steel line pipe is familiar to the offshore oil and gas industry. In a clad line pipe, the corrosion-resistant alloy forms a complete barrier layer on the internal surface of carbon or low-alloy steel pipe (usually referred to as the "backing steel"). In general, use of clad or bi-metal-lined pipe allows the economic use of expensive CRA materials.

Corrosion resistance to the process environment is provided by the internal CRA clad layer, typically 2.5-3.0 mm thick, while the less expensive carbon backing steel provides the line pipe with the required strength and toughness to maintain the mechanical integrity.

Clad line pipe can be manufactured by various techniques that include the forming and welding of hot roll bonded plate, hot co-extrusion, weld overlay, and manufacture of lined pipe. The details of the various methods of manufacture are well documented.^{1, 2} For Bruce Phase II development, manufacturing of the CRA-lined pipe was by a process involving hydraulic expansion of a CRA liner pipe inside a carbon-steel outer pipe. The finished product is supplied as bi-metal-lined pipe.

A more-detailed description of the manufacturing process occurs presently.

Manufacture of bi-metal-lined pipe is based upon use of traditional manufacturing routes for the primary materials, carbon-steel outer pipe, and CRA liner pipe.

Combined with the innovative hydraulic expansion process, the result is a mechanically bonded, lined-pipe product that can be manufactured economically compared with solid CRA and metallurgically clad product routes.

The cost effectiveness of bi-metal-lined pipe is demonstrated by the fact that bi-metal-lined pipe has been used extensively in the U.K., Norwegian, and Dutch sectors of the North Sea and also in the Gulf of Mexico.

Bruce Phase II development

The Bruce field, discovered in 1974, is one of the largest gas fields currently operating in the North Sea. Its reserves are estimated at approximately 3 tcf of gas and 222 million bbl of gas condensate and oil. The ultimate field life is projected at approximately 25 years.

The field lies across blocks 9/8a, 9/9a, and 9/9b in the Northern North Sea, approximately 340 km northeast of Aberdeen. BP Amoco plc is operator; partners are Elf Exploration U.K., Total Oil Marine, BHP Petroleum, and VEBA Oil Nederland.

The eastern side of the field was initially developed in 1993. A subsequent study concluded that the western side of the field should be developed with a subsea scheme, designated BP Bruce Phase II Development Project.

The Phase II field has been developed with subsea production facilities consisting initially of eight subsea wells, a subsea production manifold (manufactured in solid 22% Cr duplex stainless steel and lined with rubber) connecting an 18-in. production flow line which transports well stream products to a new compression-reception platform.

The subsea facilities were developed in an alliance among BP Amoco, Kvaerner Oil & Gas, Kvaerner FSSL, Rockwater Ltd., and Heerema Marine Construction.

The eight subsea wells are grouped around a single two-head manifold structure and are operated via a multiple electro-hydraulic subsea control system.

The subsea manifold structure houses manifolds and headers, subsea control modules, and jumper connections to the production well cluster. The production manifold is connected by a pipeline bundle to a platform tow head close to the compression/reception platform.

The BP Bruce Phase II bundle consists of a 44-in. OD carrier pipe (Fig. 1) which contains an 18-in. production flow line and an 8-in. test pipeline, both of which were manufactured from bi-metal CRA lined pipe, supplied by United Pipelines and H Butting.

In addition to the two bi-metal-lined flow lines, there is a 10-in. carbon-steel gas reinjection line also supplied by United Pipelines and H Butting from Mannesmann and a subsea manifold umbilical. The Bruce II bundle is approximately 5.7 km long.

Development

The development philosophy adopted by BP for the Bruce Phase II development was to bring together a team of specialist major contractors to form an alliance with the field operating company.

Each alliance member contributed its particular expertise to the process of the development, management, design, fabrication, installation, hook-up, and operations. Each partner took a proportional share in the risk and the rewards of the overall capital expenditure.

The process operating conditions of the Bruce II development which governed the materials selection and were the design basis for the subsea flow lines were the following: temperature, 85° C. maximum; pressure, 295 bar maximum; CO2, 2.2 mol % maximum; H2S, 3 ppm maximum; chloride, 47,000 ppm.

Materials philosophy

To determine the optimum materials selection in terms of technical suitability and cost for the flow lines, Kvaerner Oil & Gas adopted a through-life costing approach. This took into account the capital expenditure and the operating expenditure throughout the life of the field.

The initial feasibility study looked at the option of using carbon steel with inhibition. The calculations showed that for the temperature profile of the flow line, carbon steel was only suitable with an unusually large corrosion allowance for straight sections.

The large corrosion allowance was deemed impractical for bends, low points, and where slugging occurred. This was because the relatively high amounts of carbon dioxide in the process water would produce carbonic acid that would in turn corrode the carbon steel. The initial study therefore indicated that a corrosion-resistant alloy would be required to satisfy the 25-year design life.

The principal requirement of the candidate CRA materials is their resistance to CO2 corrosion. It was recognized that 22% Cr duplex stainless steel (DSS) and 316L austenitic stainless steel would provide the necessary corrosion resistance in the process fluids. (The 316L can be used in this chloride-containing environment because of the absence of oxygen in the process fluids.)

A solid 316L material was unacceptable because the low proof strength of the material would have led to high wall thicknesses, thus a significant increase in the weight of the flow lines.

The CRA materials options that were evaluated were solid 22% Cr duplex stainless steel, metallurgically bonded X-65/316L, and bi-metal-lined pipe X-65/316L.

Calculations based upon prices obtained from the open market showed that the bi-metal-lined pipe was significantly less expensive compared with the 22% Cr DSS option. Although metallurgically bonded clad materials of the type X-65/316L are well proven for production flow line applications, their cost structure is only marginally better than 22% Cr DSS.

The through-life costing exercise carried out by Kvaerner Oil & Gas on the various material options showed that the most cost effective materials selection for the Bruce II development production flow lines was bi-metal mechanically bonded lined pipe.

Through-life cost calculations showed the X-65/316L bi-metal-lined pipe option to be more economic than inhibited carbon-steel line pipe with an 8-mm corrosion allowance. Therefore the decision was taken to use X-65/316L bi-metal mechanically bonded lined pipe for the production flow lines.

Following are the details of the X-65/316L bi-metal flow line dimensions:

• 18-in. production flow line: 18-in. OD x 22.18 mm W.T. + 2.5 mm, X-65/316L
• 8-in. test line: 8-in. OD x 11.09 mm W.T. + 2.5 mm, X-65/316L.

Each flow line was 5.7 km long.

Using bi-metal-lined pipe

Bi-metal mechanically bonded, lined pipe is particularly suitable for onshore pipelines or offshore submarine-pipeline applications, which are to be used in highly corrosive environments and extreme conditions of temperature and pressure.

Bi-metal-lined pipe material combinations are specifically manufactured to satisfy requirements of individual project demands, and a typical range of material options is detailed in Tables 1 [15,853 bytes] and 2 [21,706 bytes].

From the typical range of material combinations shown, it can be seen that bi-metal-lined pipe allows materials engineers and design engineers the opportunity to satisfy demands of the particular project's process environment, even for high-temperature, high-pressure applications, while at the same time optimizing the overall cost effectiveness.

In consequence, bi-metal-lined pipe combinations can be supplied to optimize the following advantages.

• Resistance to chloride and sulfide stress corrosion cracking (SCC) in environments containing CO2/Cl/H2S.
• Resistance to localized corrosion (pitting and crevice corrosion).
• Resistance to general corrosion even in aggressive acid environments.
• Resistance to erosion corrosion and corrosion fatigue.
• Ease of fabrication, using combinations of automatic plasma/gas tungsten arc welding (GTAW) for the seam weld of the liner, automatic GTAW for the seal welds, and plasma/GTAW for the girth welds.
• High mechanical strength, to reduce pipe wall thickness based upon the choice of outer carbon-steel pipe materials and the respective design code.
• Excellent coating adhesion, for corrosion and insulating coatings.

Manufacturing

Bi-metal-lined pipes are manufactured with hydraulic expansion press (Fig. 2) developed to H Butting design criteria. There are two of these hydraulic expansion presses at the mill.

The first one was commissioned approximately 8 years ago and can produce bi-metal-lined pipe in 6-m lengths (double random lengths with jointers), in the size range of 4-30 in. OD with up to approximately 40-mm W.T.

The second, commissioned in October 1995, constitutes an investment of approximately $20 million and is the largest press of its kind in the world. The press can produce bi-metal-lined pipe in 12-m lengths without jointers in the size range of 6-24-in. OD, with up to 40-mm W.T.

Fig. 3 shows a flow diagram of the manufacturing process for the bi-metal-lined pipe.

The manufacturing process initially involves manufacture of the carbon-steel outer pipe, which can be produced by seamless or welded manufacturing processes. The carbon-steel outer pipe for the Bruce II development was manufactured by a seamless route.

The CRA liner pipe is produced separately by the welded method of manufacture using welded strip or plate methods of production in accordance with the respective codes and standards.

The CRA liner pipe is telescopically aligned inside the carbon-steel outer pipe, and the assembly is placed inside a die tool consisting of two half shells and hydraulically expanded at ambient temperature with a radial pressure up to 2,500 bar (Fig. 4).

At the same time, simultaneous compression of the pipe is induced by an axially operating force of up to 2,500 kN on each end of the pipe assembly.

The simultaneous action of operating radial and axial forces in the pipe assembly contained within the die tool causes the inner CRA line pipe to be expanded by approximately 2-5% until it touches the inside wall of the outer carbon steel pipe.

The operation is then followed by a combined expansion of both the inner and outer pipe by approximately 0.5-1.0%, with the outer pipe being ultimately constrained by the closed die tool.

Consequently, bi-metal-lined pipes are produced with high dimensional accuracy so that optimum tolerances and straightness of the bi-metal-lined pipe are achieved.

Seal welds

After hydraulic expansion of the CRA liner into the carbon-steel outer pipe, the ends of the bi-metal-lined pipe are seal welded with the automatic GTAW welding process.

The reason for seal welding the pipe ends is twofold:

1. The weld effectively seals the interface between the CRA liner and carbon-steel outer pipe, thus holding out dirt or moisture during transportation, storage, and subsequent site welding.
2. The weld forms an integral part of the pipe-end weld preparation at the mill.

The presence of the seal weld means that, following machine beveling of the weld preparation, the pipe ends can be welded at site without need for further work. This means that the bi-metal-lined pipe once at site can be welded in the same way as metallurgically clad or solid CRA line pipe.

Fig. 5 shows the typical seal-weld configuration. The choice of filler metal is made upon the need to overmatch the strength of the carbon steel outer pipe and to optimize the corrosion-resistance performance of the girth weld relative to the liner grade of material.

Table 3 [11,666 bytes] presents a selection of the filler metals that have been used for both the seal welds and girth welds on various combinations of carbon steel outer pipe and CRA liner. There are usually several suitable filler metals which can be used for a particular combination of carbon-steel outer pipe and CRA liner grades.

The filler metal chosen for the seal welds on the BP Bruce Phase II bi-metal-lined pipe, material combination X-65/316L, was a nickel-based consumable ER Ni Cr Mo-7 modified. This filler metal had been successfully used on previous bi-metal-lined pipe projects.

ER Ni Cr Mo-7 yields mechanical properties which overmatch the strength of the X-65 carbon steel, and the weldment posseses the necessary ductility and fracture toughness to resist crack growth at the carbon-steel weld-to-liner interface.

The filler metal selected has low susceptibility to microstructure-segregation, thus enhancing the corrosion resistance of the weldment while reducing susceptibility to weld-metal solidification cracking.

It was a requirement of the project to control the depth of penetration of the seal weld into the liner to between 10% and 75% of the liner thickness. The use of the automatic GTAW process enables accurate control of the welding parameters.

This ensures that the seal-weld joint dimensions in terms of depth of penetration around the circumference of the carbon steel-CRA interface and into the CRA liner can be closely controlled. All seal welding was carried out in accordance with the requirements of ASME IX.

In production, the seal welds were examined at a frequency of one examination for 50 pipes. Macro examinations and hardness measurements were taken at the 3, 6, 9, and 12 o'clock positions in order to confirm the quality and integrity of the seal weld.

Specifications

In accordance with the BP Bruce Phase II philosophy, a functional specification was developed based upon the requirements of API 5LD.³

The carbon-steel outer pipe was manufactured via a seamless route with the plug mill process and in accordance with API 5L.

The project specification imposed several additional requirements that included stringent control of chemical composition, an upper limit on the yield strength, and a Charpy impact-test requirement of 50 Joules minimum average at -50° C.

There was also a requirement for strain aging test to be carried out on samples strained 3% and then aged for 1 hr at 250° C. The acceptance criteria were according to the requirement of the unaged Charpy specimens.

The carbon steel had to comply with the sour-service hardness requirement of 248Hv10 maximum.

The corrosion-resistant 316L austenitic stainless-steel liner was manufactured in accordance with the requirements of API 5LC. The project specification also imposed several additional requirements for the liner.

The principal amendment was modification to the chemical composition specified in API 5LD LC1812, which was a minimum molybdenum content of 2.5%.

The testing philosophy incorporated into the project specification was one of lot testing of the carbon-steel outer pipe at the carbon-steel mill and lot testing of the CRA liner pipe before the hydraulic expansion operation.

On the basis of this extensive testing requirement, the project required only manufacturing-procedure qualification tests on the finished bi-metal-lined pipe.

Fig. 6 summarizes the testing regime adopted for the Bruce Phase II development.

Testing

Manufacturing procedure qualification testing (MPQT) was carried out on the first-day production pipe for both the 8-in. and 18-in. bi-metal-lined pipe.

Table 4 [21,733 bytes] shows the results obtained for the finished 18-in. bi-metal-lined pipe. Also included for comparison purposes are the results for the same pipe in the prehydraulic expansion condition. On the basis of the results, the manufacturing route was considered qualified.

On this project, the bi-metal-lined pipe may operate up to the maximum design temperature of 85° C. As a result of the different amounts of thermal expansion between the CRA liner and carbon-steel outer pipe at the maximum design temperature, compressive forces would be introduced into the CRA liner.

Rockwater determined the compressive load that could develop at the maximum operating temperature owing to the differences in the coefficients of thermal expansion.

In order to verify that the bi-metal-lined pipe could withstand the compressive loads envisioned in the bundle, a full-scale axial compression test was undertaken by an independent research center.

A test sample of the bi-metal-lined pipe approximately 1.5 m in length was taken from a production pipe. The sample was subjected to an axial compression test: the loading on the end face of the pipe. A series of strain gauges were attached to the test samples at various planes and locations along the inner and outer surfaces of the bi-metal-lined pipe.

The test sample was then subjected to increasing increments of compressive loading, and the performance of the liner was fully monitored during all stages of the loading.

Analysis of the test results led to the conclusion that no buckling of the CRA liner had occurred at the loads which would prevail in the bundle.

Coating; fabrication

The 18-in. bi-metal production flow line was coated for insulation purposes with a three-layer polypropylene system. The coating system was approximately 1 in. thick.

Conventional production routes, which ensure a good surface finish on the outside of the pipe, manufacture the carbon-steel outer pipe of the bi-metal-lined pipe.

This advantage of the bi-metal-lined compared to solid CRA meant that for the Bruce Phase II development, the coating was undertaken with use of standard manufacturing procedures, with standard blasting techniques, and avoided using special blasting mediums.

In all, 514 pipe joints were successfully coated.

Fabrication of the Bruce Phase II bundle was completed by Rockwater Ltd. at the company's Wick, Scotland, plant, adjacent a beach to facilitate launching the bundle into the North Sea.

The 18-in. bi-metal-lined pipe flow lines were initially fabricated into 24-m double joints manufactured with a combination of manual GTAW and submerged arc welding (SAW) welding processes.

The GTAW process was used for the root and hot passes. The welds were filled and capped with the SAW process.

The filler metal used to fabricate all the joints was a duplex grade, 2209. The duplex wire was selected by the fabricator because it was considered an ideal choice for the bi-metal-lined pipe materials combination of X-65 and 316L because its corrosion resistance matched that of the 316L liner and its strength matched that of the X-65 carbon-steel outer pipe.

The SAW welding was carried out with a compatible flux designed to maintain the correct austenite-ferrite phase balance.

The 24-m double lengths were then welded into the line over five manual GTAW welding stations.

The 8-in. flow lines were welded with the manual GTAW process. A firing line was established with up to four welding stations producing 500-m length spools.

When entire sections of the bundle were completed, the bundle was gradually moved up the fabrication site on a track, until the entire 5.7-km bundle was fully fabricated and connected to the tow heads.

The on site welding at Wick was carried in accordance with the requirements of BS4515 1996.⁴ All girth welds were subjected to 100% inspection with gamma radiography. Evaluation of the radiographs was carried out in accordance with the requirements of BS4515.

In the case of the 8-in. x 11.1 mm + 2.5-mm test line, the total number of welds carried out was 479. The number of repairs was eight with a total repair length of 280-mm plus one cut-out. This situation constituted a repair rate of 0.29%.

In the case of the 18-in. production flow line, the total number of welds carried out was 511. The number of repairs required was 13, with a total repair length of 650 mm plus two cut-outs. This constitutes a repair rate of 0.48% for the production flow line.

The two sets of weld repair rates clearly demonstrate the excellent weldability of the bi-metal-lined pipe.

U.S. MMS looks at near-term regulatory action offshore

THE U.S. MINERALS MANAGEMENT SERVICE (MMS), part of the Department of Interior (DOI), will be looking at several offshore-pipeline regulatory issues in the near future, according to Chris Oynes, MMS Gulf of Mexico regional director.

He spoke in March to the 2nd International Deepwater Pipeline Technology Conference in New Orleans.

Cathodic protection

A recent workshop on corrosion control for marine structures and pipelines, Oynes said, discussed MMS' regulatory agenda for offshore pipelines and specifically the need for special cathodic-protection design criteria for deepwater pipelines (1,000 ft water depth).

Included were members of oil and gas industry, academics, vendors, and regulators. These special design needs were identified from recent deepwater-project experiences in water depths 1,000-5,000 ft.

The group concluded that the anode chemical composition and spacing requirements must be modified from what is typically done for shallow water because lower temperatures in deepwater result in lower electrical conductivity. These conditions prompt the need for special chemical composition and more stringent anode spacing to provide adequate protection.

Oynes said MMS' gulf regional office initiated the process for publication of a safety alert to inform all Offshore Continental Shelf (OCS) operators of these considerations. The safety alert will likely be published this month.

Flushing, abandonment

During April, MMS began looking at the possibility of changing the flushing and abandonment requirements for out-of-service pipelines. At present, out-of-service lines must be flushed of hydrocarbons after 1 year and abandoned if not returned to service after 5 years.

MMS may commission a study to establish risk-based flushing and abandonment requirements for OCS pipelines. Based on the results of the study, the 1 and 5-year requirements may be changed depending upon the type of service and/or age of the pipeline.

The study will be completed in 12-18 months.

Regulatory compatibility

Finally, as provided in the revised Memorandum of Understanding between DOI and the Department of Transportation (DOT), Oynes said MMS will be working with DOT's Office of Pipeline Safety (OPS) to make offshore pipeline regulations compatible. The revised memorandum was signed Dec. 10, 1996, and the MMS implementing regulations published Aug. 17, 1998, in the Federal Register (FR 43876 - 43881).

Beginning later this year, the two agencies will be reviewing their respective regulations to "facilitate compatible regulatory requirements" for all OCS pipelines whether under DOI or DOT jurisdiction.

Other issues, according to Oynes, include the need for development of tool standards for pipeline intelligent pig inspections and reporting requirements. Such standards are needed to maintain an effective pipeline-inspection program.

Also, MMS is seeing increased cases in which conflicts have arisen between pipeline activities and OCS drilling and development. MMS prefers companies to resolve those conflicts among themselves, recognizing the multiple-use concept of the OCS.

Source:

• http://www.tenaris.com/en/Products/OffshoreLinePipe/SolidCRACladandLinePipes.aspx
• http://www.ogj.com/articles/print/volume-97/issue-18/in-this-issue/general-interest/bi-metal-cra-lined-pipe-employed-for-north-sea-field-development.html

Flexible Riser

Flexible pipe has been a successful solution for deep and shallow water riser and flowline systems worldwide. In such applications the flexible pipe section may be used along the entire riser length or limited to short dynamic sections such as jumpers. 2H Offshore’s experience covers all these applications from the shortest wellhead jumpers, used on top tensioned risers, to the deepest and longest catenary riser solutions.

Many of the analysis methods and design techniques developed for flexible pipe in the early 1980s have been extensively developed and enhanced by 2H to meet the challenges offered by steel catenary risers. These same enhanced methods are now routinely applied to flexible pipe allowing efficient and accurate assessment of flexible pipe response even under the most severe and complex loading conditions.

Typical issues covered include:

• Pipe cross section specification
• Material selection
• Global analysis
• End fitting specification
• Bend restrictor/stiffener design and specification
• Testing and qualification
• Installation and pull-in procedures
• Operational procedures
• Inspection and monitoring
• Repair

2H personnel have over 25 years engineering experience with flexible pipe covering specification, engineering, procurement, installation, operation and inspection. Sister company Aquatic provides flexible pipe installation services and equipment such as powered reels for flexible pipe installation.

As the age of the installed flexible pipe based riser increases, it has become increasingly important to monitor these systems. Furthermore it has become necessary to apply systematic integrity management methods to maintain integrity and capture degradation before it results in catastrophic failure.

2H Offshore provides such integrity management services to the oil majors using risk based approaches and have developed monitoring solutions to detect structural degradation of critical interfaces typically at the vessel adjacent to the end fittings.

Source:

Wax Inside Pipeline Removal

Waxes in crude oil

Paraffin wax produced from crude oil consists primarily of long chain, saturated hydrocarbons (linear alkanes/ n-paraffins) with carbon chain lengths of C18 to C75+, having individual melting points from 40 to 70°C. This wax material is referred to as “macrocrystalline wax.” Naphthenic hydrocarbons (C18 to C36) also deposit wax, which is referred to as “microcrystalline wax.” Macrocrystalline waxes lead to paraffin problems in production and transport operations; microcrystalline waxes contribute the most to tank-bottom sludges. Fig. 1 shows the generic molecular structures of n-paraffins, iso-paraffins, and naphthenes. The n-heptane structure is an example of a “normal” paraffin; 2-methyloctane is an “iso” paraffin and n-butylcyclopentane is a naphthene. These specific n-paraffins and naphthenes are too small to crystallize as wax deposits (i.e., outside the carbon-number range specified above). The drawings illustrate the type of structures involved.

• 

  Fig. 1—Structures of hydrocarbon classes involved in wax deposition.

Waxes isolated from crudes can contain various amounts of all classes: n-paraffins, naphthenes, and iso-paraffins. For example, waxes derived from several Venezuelan crudes showed n -paraffin/(cyclo + iso paraffin) ratios ranging from 1.28 to 0.23. The iso-paraffins of the 2-methyloctane type (Fig. 1) are more likely to be included in a wax deposit than the more highly branched alkanes.

A “clean waxy crude” is defined as a crude oil that consists of only hydrocarbons and wax as the heavy organic constituents. “Regular waxy crudes” contain other heavy organics in addition to the waxes (e.g., asphaltenes and resins). These heavy organics have interactions with the crude, which can either prevent wax-crystal formation or enhance it.

More information on the characteristics of waxes in crude oil can be found in Asphaltenes and waxes.

Phenomenology

As the temperature of the crude drops below a critical level and/or as the low-molecular-weight hydrocarbons vaporize, the dissolved waxes begin to form insoluble crystals. The deposition process involves two distinct stages: nucleation and growth. Nucleation is the forming of paraffin clusters of a critical size (“nuclei”) that are stable in the hydrocarbon fluid. This insoluble wax itself tends to disperse in the crude.

Wax deposition onto the production system (“growth”) generally requires a “nucleating agent,” such as asphaltenes and inorganic solids. The wax deposits vary in consistency from a soft mush to a hard, brittle material. Paraffin deposits will be harder, if longer-chain n-paraffins are present. Paraffin deposits can also contain:

• Asphaltenes
• Resins
• Gums
• Fine sand
• Silt
• Clays
• Salt
• Water

High-molecular-weight waxes tend to deposit in the higher-temperature sections of a well, while lower-molecular-weight fractions tend to deposit in lower-temperature regions. Prior to solidification, the solid wax crystals in the liquid oil change the flow properties from a Newtonian low viscosity fluid to a very-complex-flow behavior gel with a yield stress.

Coping with waxes

The primary chemical parameter to establish is the critical temperature at which these wax nuclei form—the wax appearance temperature (WAT). The WAT (or “cloud point”) is highly specific to each crude. The WAT value is a function of:

• Oil composition
• Cooling rate during measurement
• Pressure
• Paraffin concentration
• Molecular mass of paraffin molecules
• Occurrence of nucleating materials such as asphaltenes, formation fines, and corrosion products
• Water/oil ratio
• Shear environment

A variety of experimental methods have been used to obtain this number. Among these are:

• Differential scanning calorimetry (DSC) - measures the heat released by wax crystallization
• Cross polarization microscopy (CPM) - exploits the fact that insoluble wax crystals rotate polarized light, but liquid hydrocarbons do not
• Filter plugging (FP) - measures the increase in differential pressure across a filter, which can be attributed to wax-crystal formation
• Fourier transform infrared energy scattering (FTIR) - detects the cloud point by measuring the increase in energy scattering associated with wax solidification

Each of these techniques has its advantages and disadvantages. A comparison/review of these methods is found in Monger-McClure, et al. In testing, cloud points, measured by each of the four methods, agreed with the average value of all methods within 3 to 5°F.

Of more importance, is how well laboratory-measured cloud points anticipate WATs found in the field. Measured cloud-point data should only match field results for wells producing at low shear (high shear rates tend to delay the deposition of waxes). Another inherent problem is that the cloud-point measurement sees the precipitation of the most insoluble paraffin, not the mass of lower-molecular-weight paraffins that might contribute the major amount of wax deposit. Nevertheless, CPM measurements have been found to correlate well with the temperature at field deposition, more so than optical techniques that required a greater mass of wax to register a signal. A major problem in correlating these measurements and simulations with field experience is the acquisition of good field data. Illustrative of the state of the art in interpreting these measurements is that closer agreement is found between stock-tank oil measurements and field experience, even though it is live oil that is being produced.

An alternative to the measurement of cloud point is its prediction from compositional data by thermodynamic models. These models can predict cloud point as the temperature at which the first infinitesimal amount of wax appears, as well as predicting that mass of wax precipitating out of solution that, from experience, corresponds to field deposition. Models that use detailed n-paraffin composition input data, as obtained from high-pressure gas chromatography, generally outperform models based on less specific information like compositions to C7+ [the numbers are more generally available in the routine pressure/volume/temperature (PVT) reports].

Paraffin deposition models

Given the cloud point, what is the propensity for wax precipitation during the production and, in particular, the pipelining and processing of the crude? This is the regime of “paraffin deposition models.” These are engineering simulators used to predict wax buildup in flowing systems, taking into account such parameters as:

• Heat transfer
• Phase behavior of the crude
• Flow regime
• Wax deposition kinetics
• Shear rate
• Diffusivity
• Wall conditions (roughness, coatings, scale)
• Produced-water/oil ratio

Prevention/inhibition

As with other solids-depositing problems, prevention can be more cost effective than removal. One key to wax-deposition prevention is heat. Electric heaters can be employed to raise the crude oil temperature as it enters the wellbore. The limitations are the maintenance costs of the heating system and the availability of electrical power. As with hydrates, maintaining a sufficiently high production level may also keep the upper-wellbore temperature above the WAT. In addition, high flow rates tend to minimize wax adherence to metal surfaces because of the shearing action of the flowing fluid. Insulated pipelines are also an alternative to minimize, if not eliminate, the problem, but the cost can be prohibitive for long pipelines.

Wax deposition can be prevented, delayed, or minimized by the use of dispersants or crystal modifiers. As with asphaltenes, paraffin-wax characteristics vary from well to well. Chemicals that are effective in one system are not always successful in others, even for wells within the same reservoir. “For this reason it is of fundamental importance to establish a good correlation between oil composition and paraffin inhibitors efficiency, leading to an adequate product selection for each particular case, avoiding extremely expensive and inefficient ‘trial-and-error’ procedures.”

Crystal modifiers

Paraffin-crystal modifiers are chemicals that interact with the growing crude-oil waxes by cocrystallizing with the native paraffin waxes in the crude oil that is being treated. These interactions result in the deformation of the crystal morphology of the crude-oil wax. Once deformed, these crystals cannot undergo the normal series of aggregation steps. Types of paraffin-crystal modifiers include:

• Maleic acid esters
• Polymeric acrylate and methacrylate esters
• Ethylene vinyl acetate polymers and copolymers

Dispersants

Dispersants act to keep the wax nuclei from agglomerating. Dispersants are generally surfactants and may also keep the pipe surface water wet, minimizing the tendency of the wax to adhere. Some water production is required, of course. High levels of water alone may maintain the system in a water-wet state. As with scale prevention, a smooth surface tends to decrease wax adherence. However, the operational problem is to maintain such a surface for an extended period of time. Various forms of erosion are highly detrimental.

Obviously, these inhibitors must be delivered into the crude oil at temperatures above the WAT. This need not cause a problem for surface equipment, but it could cause a problem for wellbore treatment, if the bottomhole temperatures are low.

Removal of deposits

Removal of wax deposits within a wellbore is accomplished by:

• Cutting
• Drilling
• Chemical dissolution
• Melting—the use of hot oil, hot water, or steam

Of these, the use of hot oil has been the most popular, normally pumped down the casing and up the tubular. It is intended that the high temperature of the liquid phase heat and melt the wax, which then dissolves in the oil phase. Using the bottom-up delivery approach, hot oil first reaches those waxes most difficult to melt. The higher in the tubular the hot oil proceeds, the lower its temperature becomes, thereby reducing its wax-carrying capacity. Hot oiling can cause permeability damage, if the fluid containing the melted wax enters the formation.

Hot water, hot-water/surfactant combinations, and steam are alternatives to hot oiling. Plain hot-water treatments do not provide the solvency required to remove the wax, hence the use of surfactants to disperse the wax. The advantage of water is its greater heat capacity.

Chemical generation of heat has also been proposed as a method of melting wax deposits. One field-tested scheme uses the thermochemical process of reacting two specific nitrogen salt solutions, acidic ammonium chloride and sodium nitrite; an orgainc solvent is included to keep the wax in solution after the system has cooled.

Various aromatic solvents can be used to dissolve the wax. These are generally not heated, relying solely on the solvency properties of the fluid. As with asphaltene dissolution, o-xylene has been one of the more effective solvents for waxes. Kerosene and diesel tend to be poor solvents. However, as with asphaltenes dissolution, one solvent does not necessarily work equally well on all wax deposits; an example of solvent screening procedures is given in Ferworn, et al.

Pigging is the primary mechanical method of removing wax buildup from the internal walls of pipelines. The pig cuts the wax from the pipe walls; a bypass can be set with a variable-flow pass, allowing the pig to prevent wax buildup in front. Pig sizing can vary, and multiple pig runs with pigs of increasing size can be used. For subsea pigging, a looped flowline is required or a subsea pig launcher for a single flowline. The major uncertainty in this operation is the wax hardness as it is formed in the pipeline.

Coiled tubing with the appropriate cutters at the end also can be used for wax removal—the drawback for pipeline cleaning being the limited reach of the coiled tubing. For wellbore cleaning this is obviously less of a problem.

Source:

http://petrowiki.org/index.php?title=Wax_problems_in_production&printable=yes

Pipeline Coating Protection in General

We have already discussed about cathodic protection in my previous article. In this article, I would like to share about pipeline coating protection in general.

The application and maintenance of anticorrosion protection is one of the most important aspects affecting pipe manufacturing, laying and operation of pipelines. The two essential components of pipeline protection are: Anticorrosion Coatings Cathodic Protection Some argue that the latter is more important than the former. Both are vital to ensuring the long life and operating safety of cross country pipelines.  coated pipes on the right–of–way   For over 55 years, the pipeline coating industry concentrated on field–applied coatings. Long distance pipelines were coated with automatic equipment — Line Travel CPT (Clean, Prime, Tape) machines. For short lengths of pipe, small, hand operated equipment was used. The main advantages of coating on site were cost and speed. Major progress in development of coating materials and technologies as well as rising demands of users made plant applied coatings the desired alternative, as they promised to be cheaper and more reliable in comparison to field–applied. Since the quality of coating achieved with plant applied coatings is better — pipe can be cleaned to a higher standard and the application is not sensitive to weather or terrain conditions — the industry has made the shift to primarily plant applied coatings. They can now be applied at the pipe mill or at coating plants nearer to the right–of–way. As, semi–stationary plants become more widespread, they allow the end–user and contractor to deliver pre–coated pipe almost damage free, with improved logistics and delivery and in some cases "added value" for in–country application.    factory–coated pipe; girth welds protected with field–installed Canusa sleeves  As a rule, anticorrosion coatings may be divided into several categories: Plant Pipe Coating The most common types of plant–applied coatings are: Epoxy coating — is available in either “thin film” or double layer Three–layer coating Hot Tape coatings — include the use of heat shrink tape Cold Tape coatings Hot Enamel coatings Yard Pipe Coating Some of the above coating systems may be applied in a yard environment. Most suitable are: Hot Tape coatings Liquid coatings Cold Tape coating Hot Enamel coatings Field Pipe Coating (“over–the–ditch”) Cold Tape coatings — various types are available for special conditions such as high–shear resistance or high temperature resistance Hot Tape coatings — a line travel only Field Joint Protection Cold PVC or PE Tape coatings Liquid coatings — these range from coal tar polyurethane to urethane to epoxy Heat Shrink Sleeves — the most widely used form of joint protection available Coating Rehabilitation Cold Tape coatings Liquid coatings

Source:

http://www.arguslimited.com/en/pipeline_corrosion_protection

Pipeline Thermal Insulation

The need for high performance, robust and dependable products, has never been greater in the offshore industry, especially as it continues to move towards even more challenging applications. The thermal insulation of offshore pipelines, has an important role to play to ensure the smooth running of a facility and as such, is a key element of many offshore drilling projects. However, as budgets get leaner, fluids get warmer and water depths get deeper, can the sector keep up? I say “yes” and would argue that innovative synthetic rubber-based solutions not only address these concerns and provide a reliable alternative, but are the only true choice for offshore pipeline thermal insulation. 

The offshore oil and gas industry is notorious for continuously pushing the limits. The exploration of offshore gas/oil has been moving to more and more deepwater fields and demanding that wells be drilled deeper and reach further in order to provide more cost-effective and safe well completions. In addition, the requirement to extract more oil and gas than ever before, and exploit ever harsher reservoir environments in new locations around the world, adds a further challenge. 

As the water depth becomes greater and the reservoir is located deeper underneath the seafloor, additional pressure is put on the performance of oil and gas products which must now be able to cope with much higher pressures and temperatures than shallow reservoir products. 

As such, particularly in this difficult economic climate, customers require solutions which are not only superior when it comes to performance, but more cost-effective, focusing more on price and longer lifetime. Not long ago customers required products that could last 20 years; now it’s often up to 40 years. 

When it comes to material selection to handle these challenges, rubber-based materials are, not surprisingly, becoming a more popular solution within the offshore industry as rubber is an extremely flexible and durable material. Compared to alternative materials, such as steel and fiberglass, rubber has an extensive temperature range and exceptionally high pressure resistance, it is a flexible material that can damp, seal and protect, and most of all, has an extremely long lifetime. 

GOING WITH THE FLOW
So, as exploration and drilling go deeper, the need for reliable and efficient thermal insulation increases; flow assurance is a critical element of deep and ultra deepwater developments, in particular pipelines. Effective insulation of subsea structures helps maintain flow rates, optimise productivity and reduce processing costs. It also provides optimum defense against wax and hydrate formations. 

When reservoir fluids reach the subsea structure they are typically a high temperature mix of condensed hydrocarbon gases, liquid paraffinic materials, waxes and water. As the fluid progresses through the structure to the processing facility or during a system “cool-down” cycle, heat loss is apparent to the surrounding ocean. As the temperature decreases, waxes and hydrate crystals may deposit, leading to potential flow loss and eventual system blockage. Insulation therefore becomes a necessary part of this process in order to avoid this formation of hydrate plugs and wax build-up (paraffin). The formation of wax and hydrates occurs when the oil or gas composition is depressurised and exposed to the low seawater temperature at the seabed. 

A hydrate is formed when crystalline water is stabilised and light hydrocarbon molecules are captured in the crystal lattice. Hydrates can be formed at high pressures and at temperatures around +68 °F to 77 °F (+20 °C to +25 °C). Without insulation the cold seawater would rapidly cool the fluid, allowing it to create hydrate and wax formations, and making it impossible for a safe flow. 

Thermal insulation materials are often applied in order to prevent formation of hydrate and wax during a shutdown scenario. During shutdown, the extra insulation gives sufficient time for inspection of the subsea pipe and equipment, so engineers can have time to solve production problems and for methanol or glycol injection. 

MEETING DEMAND
The increasing challenges faced by the offshore industr y have spurred manufacturers to consistently push to develop products that can keep up with the demands of the offshore engineer. 

However, it’s not always about finding completely new solutions. Manufacturers must continuously look at their current product portfolios to find new ways to make existing products work even harder than they already do, if they are to stay ahead of the game. 

As such, some leading manufacturers are reassessing subsea thermal insulation materials, which have been successfully installed throughout the subsea oil and gas industry for many years, to see how best to enhance their performance in line with these growing demands. 

The latest generation of subsea insulation solutions, an example of this dedicated improvement from one leading manufacturer, have a k-value of 0.13 W/mK, can be used up to 9842ft (3000m) deep and utilised of liquid temperatures up to +311 °F (155 °C), as well as external temperatures as low as -31 °F (-35 °C). In order to provide even more flexibility when it comes to design and logistics, it now also allows for mobile production and can be installed on-site, at a water depth of 9842ft (3000m). 

A LAYERED APPROACH
These flexible insulation systems consist of a three-layer buildup. First, an inner layer for corrosion and/or Hydrogen Induced Stress Cracking (HISC) protection; this could be a Neoprene compound that is qualified up to +203 °F (+95 °C), or an EPM compound that is qualified up to +311 °F (155 °C). Both compounds provide excellent corrosion or HISC protection, and have been extensively tested for adhesion, aging and cathodic disbondment.

The middle layer has been designed to provide the thermal insulation protection and various compounds are applicable depending on the specific requirements. The compounds provide a k-value of 0.13 W/m2K up to 0.19 W/m2K. The flexibility and stability of the rubber makes this an excellent choice with respect to thermal expansion. 

The insulation layer is protected by the outer layer. This is a strong and robust layer that provides excellent seawater and mechanical protection and has a successful track record as far back as the early seventies in the North Sea. 

The insulative elastomer coating system used is a development based on ordinary rubber technology and consists of a rubber elastomer chemically modified to give a very high insulating property, while maintaining its inherent rubber properties in respect to sea-water resistance, pressure resistance, mechanical properties and temperature. By utilising a solid rubber-based coating, these new products have very good thermal insulation properties while providing maximum corrosion protection. 

STANDING THE TEST OF TIME
With the lifetime of an oil field expected to be a minimum of 25 years and design temperatures of the field var ying throughout (up to +392 °F/ +200 °C), it is impor tant that products can prove they stand the test of time. Continuous and extensive testing is the only way to remain at the forefront of material development and lies at the heart of material advances and product solutions. 

Extensive test programming has been carried out on these next-generation insulation solutions to prove their integrity for the lifetime of the field. They are designed to last the life of the subsea project (20 to 40 years), are maintenance free and will normally never be replaced. 

ALTERNATIVE INNOVATIONS
But it's not just about subsea pipelines; leading manufacturers are also looking to develop, new and unique solutions to maximise topside offshore pipe insulation. 

This is because the insulation of topside pipes usually involves the use of mineral wool to provide insulation, with an outer shell of steel for protection. However, while this insulation system is meant to be water tight, experience shows that this isn’t always the case and humidity can often penetrate into the insulation. This will often result in the corrosion of the steel protection layer and a reduction in thermal performance. 

Therefore, it is of high importance that it’s a stratum of air is placed between the insulation and the steel pipe to avoid any damage to the pipe. Historically engineers have made these air gaps between the pipe and thermal insulation using an additional sheet of metal applied in a wave pattern. However, this method can cause undesirable side effects including corrosion of the metal sheet and injury to engineers during work due to its sharp edges. 

In a bid to provide a high performance product, which not only provided a reliable solution, helping to guarantee thermal performance, but one that eliminated the undesirable effects that comes with traditional methods of creating an air gap, leading manufacturers developed a new rubber-based alternative. 

This unique solution has been specifically developed to effectively create a one to two centimeter air gap between the pipe and insulation, thereby avoiding the corrosion that can occur. By stopping direct contact between the insulation material and the pipe, this new solution prevents any damage to the corrosion protection on the pipe, helping to guarantee thermal performance. 

PEACE OF MIND
This latest innovation, which is unique to the market, provides a reliable and extremely durable solution to a common problem within the offshore topside insulation market. Furthermore, its rubber construction means that it will last the life of an offshore project, as well as being maintenance free, providing reassurance to the offshore engineer. 

It can also be easily installed without using hot work or special tools, and can be connected and split to the desired length using just a pair of scissors, making the installation quick and easy and without any additional safety actions, in turn reducing downtime. 

Extensive testing has also been undertaken to ensure that the product is qualified for lifetime performance; it has been qualified for use up to +302 °F / +150°C continuous service temperature, for more than 30 years. 

CONCLUSION
As the offshore oil and gas industry continues to push the limits when it comes to demanding offshore applications, the need for reliable and durable solutions that deliver proven performance for critical thermal insulation installations, has never been greater. 

With the formation of hydrate plugs and wax build up (paraffin), or corrosion of topside steel pipes, a real risk for offshore engineers, rubber-based solutions provide a practically incompressible, seawater and impact-resistant solution that has very good thermal insulation properties and also provides maximum corrosion protection. They are designed to last the life of the subsea project (20 to 40 years), are maintenance free and will normally never be replaced, giving peace of mind to the offshore industry.

Source:

http://www.chemtech-online.com/O&G/Grethe_aug_sept12.html