Offshore Pipeline Corrosion Prevention

Lingkungan yang akan dihadapi oleh pipa lepas pantai adalah air laut. Air itu sendiri dapat memicu terjadinya korosi pada pipa, apalagi ditambah dengan kandungan garam. Pipa yang diletakkan di dalam air yang mengandung garam lebih rawan terhadap korosi dibanding pipa yang diletakkan di dalam air tawar.

Korosi pada pipa cukup membahayakan kondisi pipa karena dapat menyebabkan kerusakan dinding pipa. Bila terlalu lama dibiarkan, akan timbul lubang-lubang kecil pada dinding pipa yang memicu terjadinya kebocoran. Oleh karena itu, perlu adanya langkah pencegahan terhadap korosi pada pipa lepas pantai. Apalagi jika jalur pipa yang dimiliki cukup panjang dan terletak di perairan dalam, biaya perbaikan bila terjadi kerusakan akan sangat mahal.

Langkah pertama dan utama untuk mengendalikan korosi pada pipeline adalah dengan menggunakan material pelapis (coating). Perlu diketahui pula prinsip bahwa korosi pada pipa tidak akan terjadi bila pipa diisolasi terhadap kontak langsung dengan lingkungan luar. Material coating akan efektif untuk mencegah terjadinya korosi, bila:

• Merupakan insulator listrik.
• Terdiri dari lapisan yang sempurna dan akan bertahan seiring berjalannya waktu.

Lebih jauh lagi, sebuah spesifikasi lebih lengkap mengenai standard coating pada pipa telah dipublikasikan oleh National Association of Corrosion Engineers (NACE) melalui NACE Starndars RP0169-96 Section 5, yaitu:

• Insulator listrik yang efektif.
• Mampu menahan
• Mudah diterapkan/diaplikasikan.
• Adhesi yang baik dengan permukaan pipa.
• Mampu menahan damage saatproses handling dan instalasi.
• Mampu mempertahankan resistivitas listrik seiring berjalannya waktu.
• Mudah diperbaiki.
• Tidak beracun bagi lingkungan sekitar.

Beberapa factor yang perlu dipertimbangkan dalam menentukan sebuah coating pipa:

• Kondisi lingkungan
• Akses terhadap pipeline
• Temperatur operasional pipeline
• Temperatur normal saat penyimpanan, shiping, konstruksi, dan instalasi
• Kondisi geografis dan fisik pada lokasi
• Jenis coating yang sudah ada pada pipeline
• Handling and storage
• Metode instalasi
• Biaya
• Persiapan pada permukaan pipa sebelum dilakukan pelapisan

Berikut adalah jenis coating pada pipa beserta karakteristiknya.

Sebagai pelengkap coating, metode pencegahan korosi berikutnya adalah Cathodic Protection (CP). Prinsip CP adalah untuk mengurangi laju korosi pada lapisan logam dengan menjadikannya sebuah katodik bagi suatu sel ekletrokimia.

Korosi terjadi ketika ada anoda dan katoda yang terhubung secara elektrik dan adanya elektrolit yang berupa air laut maupun air di dalam tanah. Ketika itu pula, terjadi pertukaran elektron yang kita sebut korosi. Jadi untuk melindungi pipa yang sebagian besar unsur penyusunnya terdiri dari Fe dan Carbon sebaiknya memilih anoda yang lebih aktif (negative) dari kedua unsur tersebut. Sehingga untuk CP pada jalur pipa bawah laut biasanya digunakan unsur Al dan Zinc. Dari sinilah muncul istilah ‘anoda korban’, yaitu sel elektrikimia yang ‘dikorbankan’ untuk terjadi korosi padanya demi menghindari korosi pada pipa.

Ilustrasi prinsip kerja CP.

Sumber: Control of Pipeline Corrosion (A.W. Peabody, 2001)

Secara umum, CP dibagi menjadi 2 kategori yaitu, galvanic anode system dan impressed current system. Biasanya, galvanic anode system diperuntukkan untuk struktur pipa bawah laut sedangkan impressed current system digunakan pada onshore pipeline.

Anoda korban terpasang pada linepipe.

Sumber: http://stoprust.com/asset-solutions/pipeline-cathodic-protection-systems/

Anoda korban terpasang pada pipa.

Sumber: http://oanaalexandra.hubpages.com/hub/Coastal-Engineering

Seorang CP Engineer bertugas untuk menentukan tingkat CP yang dibutuhkan agar laju korosi pada pipa dapat ditekan hingga mencapai level yang dapat ditoleransi.

Berikut adalah beberapa konsep penting mengenai perlindungan pipa terhadap korosi:

• Pemilihan coating yang terbaik dan aplikasi yang sesuai merupakan tahap yang sangat penting.
• CP harus menjadi ‘suplemen’ bagi coating untuk mencapai perlindungan 100%
• In-the-gournd tets lebih baik dibanding laboratory test.
• Cathodic disbondment test adalah tes terbaik untuk mengukur performa suatu coating.
• The current required for CP is the best measure of coating performance.
• Ketebalan optimum suatu coating perlu diperhatikan.
• Tegangan tanah merupakan salah satu permasalahan utama.
• Selection of the best appropriate system is important, but proper application is the most important consideration.

Sumber: 

Control of Pipeline Corrosion (A.W. Peabody, 2001)

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id

Pipeline Global Buckling

Terdapat berbagai macam fenomena kerusakan pada pipa bawah laut, diantaranya adalah korosi, crack, dent, dan buckle.

Buckle adalah ketidakmampuan suatu struktur dalam menerima beban (tegangan) yang bekerja padanya. Akibatnya adalah terjadi perubahan/deformasi bentuk pada struktur tersebut, baik dalam skala kecil maupun skala besar.

Menurut ASME B31.8-2010: Buckle is a condition in which the pipeline has undergone sufficient plastic deformation to cause permanent wrinkling in the pipe wall or excessive cross-sectional deformation caused by bending, axial, impact, and/or torsional loads acting alone or in combination with hydrostatic pressure.

Pada struktur material baja akan mengakibatkan terjadinya penyok atau bengkok. Penyebab yang umum terjadi adalah penampang struktur yang terlalu slender/ramping (memiliki kapasitas kecil) sehingga relative mudah terdeformasi.

Pada pipa bawah laut, sepanjang sekian meter atau feet pipa akan mengalami lendutan yang cukup parah akibat tidak mampu menahan beban yang diterimanya. Kondisi ini dinamakan Global Buckling. Berdasarkan arah lendutannya, Global Buckling dibagi menjadi 3, yaitu:

• Ke arah bawah, bila terjadi pada free span. Free span merupakan kondisi dimana suatu section pipa tidak bersentuhan langsung dengan seabed, ataupun tertopang oleh suatu support. Hal ini tentu membuat pipa tersebut ‘bebas’ bergerak kemana saja akibat pengaruh dari dalam dan luar pipa.

• Ke arah samping/horizontal (lateral buckling) pada seabed.

• Ke arah atas/vertikal (upheaval buckling) pada pipa yang dikubur didalam tanah. Pipa akan menerobos naik ke permukaan seabed.

Pada saat operasional, temperatur pipa akan mengalami kenaikan dibandingkan pada saat instalasi. Kenaikan temperatur ini akan menyebabkan pipa mengalami elongasi (memanjang) yang besarnya bergantung pada sifat mekanik material pipa. Namun untuk beberapa kondisi yang bergantung pada gaya friksi tanah, berat timbunan pipa, maupun berat pipa sendiri akan menimbulkan tipe-tipe global buckling seperti yang telah disebutkan diatas. Ditambah lagi dengan kombinasi loading seperti perbedaan temperature, tekanan (internal dan eksternal), dan gaya friksi tanah akan menghasilkan gaya aksial tekan efektif pada pipa.

Jika pada pipa terdapat lekukan awal yang terjadi akibat kesalahan instalasi atau ketidakrataan permukaan seabed dapat semakin memicu terjadinya global buckling. Karena gaya aksial tekan akan berubah menjadi gaya vertikal maupun horizontal.  dikarenakan gaya aksial tekan akibat perbedaan tekanan tidak dapat dihindari maka yang dapat diperbuat hanyalah meningkatkan tahanan terhadap displacement yang ditimbulkan buckle.

Secara umum, beberapa hal yang perlu diperhatikan untuk menghindari terjadinya buckle, antara lain:

• Berat pipa.
• Property penampang pipa.
• Ketahanan friksi antara pipa dengan tanah.
• Jenis fluida yang dialirkan.
• Perubahan temperature dan tekanan dari dalam pipa.
• Panjang pipeline.
• Kelalaian saat proses instalasi/laying pipa.
• Wilayah topografi yang dilalui pipa.
• Kondisi lingkungan yang dihadapi pipa.

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id

Pipeline Material and Grade selections

Berbagai komponen pada pipeline, seperti pipa, sambungan (flange), fittings, katup (valve), hingga mur serta bautnya memiliki spesifikasi material yang bermacam-macam, sesuai dengan kebutuhan penggunanya. Di dunia, terdapat berbagai macam spesifikasi komponen-komponen tersebut yang telah dipublikasikan kepada masyarakat, seperti yang dikeluarkan oleh American Society for Testing Materials (ASTM) dan American Petreoleum Institute (API).

Spesifikasi ASTM merupakan yang paling umum digunakan. Sedangkan spesifikasi yang dikeluarkan oleh API merupakan hasil testing yang dilakukan oleh para ahli/pakar dalam industry minyak dunia, sehingga spesifikasi tersebut sesuai dengan kebutuhan industry minyak (dan gas).

Terdapat beberapa fungsi dari standar pipa yang telah dipublikasikan, antara lain:

• Mereka menjelaskan requirements pada proses manufaktur dan testing pipa.
• Tanpa spesifikasi, pembeli pipa akan kesulitan dalam berkomunikasi dengan produsen pipa mengenai produk yang diinginkan.
• Ketika produsen pipa menandai produk mereka dengan suatu spesifikasi, itu berarti mereka dapat menajmin bahwa pipa buatan mereka terbuat dari baja berkualitas dan telah memenuhi requirements dari spesifikasi yang digunakan.

Dalam spesifikasi pipa, terdapat istilah ‘Grade’. Apa itu Grade? Grade menunjukkan jenis-jenis komponen pipeline dengan tingkat kualitas dan komposisi material yang berbeda. Contohnya, pada spesifikasi ASTM, Grade B memiliki kapasitas leleh (yield strength) yang lebih tinggi dari Grade A. Grade B memiliki komponen karbon yang lebih tinggi dibanding Grade A. Grade A, sebagai baja yang lebih ‘lembut’ menjadi lebih mudah untuk dibengkokan dan direkomendasikan untuk proses close coiling dan cold bending. Sementara Grade B memiliki kapasitas tegangan yang lebih tinggi, cocok untuk komponen peralatan mesin.

Ada berbagai variasi Grade lainnya, seperti Grade P1 da n Grade P11 (untuk pipa), Grade WPA (untuk fittings), Grade WCB dan Grade LCB (untuk valve), Grade B7 dan Grade 2H (untuk batu+mur), dan lain-lain.

Berikut adalah tabel ASTM Grades yang sering digunakan.

ASTM Grades yang sering digunakan.

Sumber: http://www.wermac.org/pipes/pipe_part4.html

Kemudian, apa arti dari A106, A335, A234, A105, dan semacamnya? Keempat karakter di depan menunjukkan spesifikasi material. Misal, A106 merupakan carbon steel pipe for high temperature service, A335 merupakan seamless ferritic alloy-steel pipe for high temperature service, A234 merupakan wrought carbon steel and alloy steel fittings of seamless and welded construction, dan lain-lain.

Sumber:

http://www.wermac.org/pipes/pipe_part4.html

http://www.industrialgroupco.com/assets/files/common-pipe-specifications.pdf

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id

Hydrotest on Offshore Pipeline

Hydrostatic testing has long been used to determine and verify pipeline integrity. Several types of information can be obtained through this verification process.

However, it is essential to identify the limits of the test process and obtainable results. There are several types of flaws that can be detected by hydrostatic testing, such as:

• Existing flaws in the material,
• Stress Corrosion Cracking (SCC) and actual mechanical properties of the pipe,
• Active corrosion cells, and
• Localized hard spots that may cause failure in the presence of hydrogen.

There are some other flaws that cannot be detected by hydrostatic testing. For example, the sub-critical material flaws cannot be detected by hydro testing, but the test has profound impact on the post test behavior of these flaws.

Given that the test will play a significant role in the nondestructive evaluation of pipeline, it is important to determine the correct test pressure and then utilize that test pressure judiciously, to get the desired results.

When a pipeline is designed to operate at a certain maximum operating pressure (MOP), it must be tested to ensure that it is structurally sound and can withstand the internal pressure before being put into service. Generally, gas pipelines are hydrotested by filling the test section of pipe with water and pumping the pressure up to a value that is higher than maximum allowable operating pressure (MAOP) and holding the pressure for a period of four to eight hours.

ASME B 31.8 specifies the test pressure factors for pipelines operating at hoop stress of ≥ 30% of SMYS. This code also limits the maximum hoop stress permitted during tests for various class locations if the test medium is air or gas. There are different factors associated with different pipeline class and division locations. For example, the hydrotest pressure for a class 3 or 4 location is 1.4 times the MOP. The magnitude of test pressure for class 1 division 1 gas pipeline transportation is usually limited to 125% of the design pressure, if the design pressure is known. The allowed stress in the pipe material is limited to 72% of SMYS. In some cases it is extended to 80% of SMYS. The position of Pipeline and Hazardous Material Safety Administration (PHMSA) is similar. Thus, a pipeline designed to operate continuously at 1,000 psig will be hydrostatically tested to a minimum pressure of 1,250 psig.

Though codes and regulatory directives are specific about setting test pressure to below 72% or in some cases up to 80% of the SMYS of the material, there is a strong argument on testing a constructed pipeline to “above 100% of SMYS,” and as high as 120% of SMYS is also mentioned. Such views are often driven by the desire to reduce the number of hydrotest sections, which translates in reduction in cost of construction. In this context, it is often noted that there is some confusion even among experienced engineers on the use of term SMYS and MOP/MAOP in reference to the hydrotest pressure.

It may be pointed out that the stress in material (test pressure) is limited by the SMYS. This is the law of physics, and is not to be broken for monetary gains at the peril of pipeline failure either immediate or in the future.

Metal stress diagram.

Source: http://www.pipelineandgasjournal.com/pipeline-hydro-test-pressure-determination?page=show

Often there is argument presented that higher test pressures exceeding 100% of the SMYS will increase the “strength” of the material and will “stress relieve” the material. Both arguments have no technical basis to the point they are made. We will briefly discuss both these arguments here:

1. Higher test pressure will “increase the strength.” As the material is stressed beyond its yield point, the material is in plastic deformation stage, which is a ductile stage, and hence it is in the constant process of losing its ability to withstand any further stress. So, it is not increasing in strength but progressively losing its strength.
2. The second argument of “stress reliving” is linked with the “increase the strength” argument. The stress relief of material is carried out to reduce the locked-in stresses. The process reorients the grains disturbed often by cold working or welding. The stress relief process effectively reduces the yield strength. Thus, it does not “strengthen” the material. Note: It may be pointed out that a limited relaxation of stresses does occur by hydro testing, but the test pressure should be less than the material’s yield point.

Another point to note here is that there is a stage in the stressing of the material where strain hardening occurs and the material certainly gains some (relative) hardness, and thereby, strength. This happens as necking begins but, at that point, unit area stress is so low that the strength of the material is lost and it remains of no practical use, especially in context with the pipe material we are discussing.

Returning to the subject of pressure testing and its objectives. One of the key objectives of the testing is to find the possible flaws in the constructed pipeline. The test develops a certain amount of stress for a given time to allow these possible flaws to open out as leakages.

Source:

http://www.pipelineandgasjournal.com/pipeline-hydro-test-pressure-determination?page=show

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id

Pipeline Corrosion

In recent years the number of corrosion failures in onshore and offshore pipelines has steadily decreased due to the introduction of corrosion management strategies by pipeline operators. A vital component in effective corrosion management is an accurate determination of corrosion growth rates. 

In-line inspection using high-resolution pigs to detect and size corrosion can become the basis for defining a future safe operating strategy. A methodology has been developed which includes the direct comparison of magnetic flux leakage or ultrasonic data between two inspection runs. Consequently, any new sites of corrosion or sites at which corrosion growth has occurred can be identified and the extent of the growth quantified. 

Utilizing the variation in corrosion depth, corrosion growth rate and material properties, and reliability methodologies the probability of failure is established as a function of time. This approach has been used for internal corrosion management, and can also be applied for management of excavation for external corrosion. Attention is given to the approaches used to estimate corrosion growth rates and the reliability methodologies which allow the probability of failure to be determined. Case studies are presented of the successful use of the above methods. 

At the start of the 1990's there were concerns over the increasing threat of corrosion to pipeline integrity. For example:

·         -Corrosion was the major cause of reportable incidents in North America

·         -Corrosion was the major cause of pipeline failure in the Gulf of Mexico

·         -Corrosion in a North American onshore oil pipeline had required over $1 billion in repairs

·    Internal corrosion along the complete length of pipelines had resulted in significant        replacement programs e.g.

However, world-wide, the number of pipeline incidents caused by corrosion (internal and external) has remained at around 25% and in North America, the number of corrosion leaks repaired each year by pipeline operators has steadily decreased in the 1990's. 

The reason for these trends is the increasing use of corrosion management technologies to reduce corrosion risks. Indeed, it is now expected that pipeline operators utilise appropriate maintenance to prevent corrosion failures. For example, a North American operator has recently been fined a record $30 million because "corrosion caused most of the (300 oil) spills and they could have been prevented with proper operations and maintenance".

Operators can now combine the benefits of high resolution inspection, detailed corrosion growth analysis and reliability methods in the development of their corrosion management strategies. 

ESTIMATION OF CORROSION GROWTH RATES 

The ability to accurately determine corrosion growth rates is an essential input parameter into any effective corrosion management strategy as it allows operators to better define and plan future rehabilitation and operating regimes. Historically corrosion growth rates have been estimated by comparing the sizes of a small sample of defects in successive inspection runs or by using equations such as de Waard and Milliams (10) for estimating rates in 'sweet' oil and gas pipelines. However, run comparison software has now been developed (11) which provides a direct comparison of the inspection signals between 2 or more inspection runs (Figure 1) and allows: 

(i) the identification of internal and/or external corrosion features which have grown between the inspection operations, 

(ii) the location of new sites of internal and/or external corrosion to be identified, and 

(iii) represent

Source

https://www.onepetro.org/conference-paper/NACE-01627?sort=&start=0&q=Pipeline+Corrosion&from_year=&peer_reviewed=&published_between=&fromSearchResults=true&to_year=&rows=10#

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id

Pipeline thermal Insulation

Grethe Hartviksen, Innovation & Technology Manager, Trelleborg OffshoreThe 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

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id