UK pipeline decommissioning provides potential for innovation

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.

Click to Enlarge

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.

http://www.offshore-mag.com/articles/print/volume-74/issue-2/engineering-construction-installation/uk-pipeline-decommissioning-provides-potential-for-innovation.html

Pipeline Construction

Pipeline construction is divided into three phases, each with its own activities: pre-construction, construction and post-construction.

 

Pre-Construction

Surveying and staking

Once the pipeline route is finalized crews survey and stake the right-of-way and temporary workspace. Not only will the right-of-way contain the pipeline, it is also where all construction activities occur.

Preparing the right-of-way
The clearly marked right of way is cleared of trees and brush and the top soil is removed and stockpiled for future reclamation. The right-of-way is then leveled and graded to provide access for construction equipment.

Digging the trench
Once the right-of-way is prepare, a trench is dug and the centre line of the trench is surveyed and re-staked. The equipment used to dig the trench varies depending on the type of soil.

Stringing the pipe
Individual lengths of pipe are brought in from stock pile sites and laid out end-to-end along the right-of-way.

 

Construction

Bending and joining the pipe
Individual joints of pipe are bent to fit the terrain using  a hydraulic bending machine. Welders join the pipes together using either manual or automated welding technologies. Welding shacks are placed over the joint to prevent the wind from affecting the weld. The welds are then inspected and certified by X-ray or ultrasonic methods.

Coating the pipeline
Coating both inside and outside the pipeline are necessary to prevent it from corroding either from ground water or the product carried in the pipeline. The composition of the internal coating varies with the nature of the product to be transported. The pipes arrive at the construction site pre-coated, however the welded joints must be coated at the site.

Positioning the pipeline
The welded pipeline is lowered into the trench using bulldozers with special cranes called sidebooms.

Installing valves and fittings
Valves and other fittings are installed after the pipeline is in the trench. The valves are used once the line is operational to shut off or isolate part of the pipeline.

Backfilling the trench
Once the pipeline is in place in the trench the topsoil is replaced in the sequence in which it was removed and the land is re-contoured and re-seeded for restoration.

 

Post Construction

Pressure Testing
The pipeline is pressure tested for a minimum of eight hours using nitrogen, air, water or a mixture of water and methanol.

Final clean-up
The final step is to reclaim the pipeline right-of-way and remove any temporary facilities.
 
Reference: “Pipeline Construction”. http://www.cepa.com/about-pipelines/pipeline-design-construction/pipeline-construction. January 2014.

Analisa pada Pipa Terkubur

Salah satu metode pengamanan pipa bawah laut adalah dengan mengubur pipa. Analisa pipa terkubur dengan menggunakan metode analisa tegangan berdasarkan interaksi antara tanah dengan pipeline. Pipa yang terkubur menerima tekanan tanah yang menghasilkan bending stress pada dinding pipa. Bersamaan dengan hal itu, tekanan juga menghasilkan gaya gesek tanah yang berlawanan dengan arah aksial pergerakan pipa.

Gambar 1. Tekanan Tanah pada Pipa

(sumber: www.pipestress.com)

Liang-Chaun Peng (1978) menganalisa tegangan pada pipa terkubur dengan lingkup:

• Gaya gesek aksial
• Gaya lateral tanah
• Pergerakan longitudinal pipa
• Pergerakan lateral pipa

Kesimpulan dari analisa yang dilakukan oleh Peng (1978) adalah:

• Untuk pipa yang terkubur, pipa akan terekspansi menjelang akhir pipa atau pada bend. Tapi pusat line tetap terkendali akibat gaya gesek tanah. Total pergerakan pada free end pipa berbanding terbalik dengan gaya gesek tanah.
• Akibat gaya lateral tanah, pergerakan di bend berkisar satu setengah dari pergerakan di free end.
• Untuk pipa standard 20 inci pada perbedaan temperature sebanyak 130⁰F, tegangan yang dihasilkan di koneksi Antara bend dan long run adalah sebanyak tiga kali tegangan ijin.
• Pipa yang terkubur tanpa perhatian khusus akan mengalami kenaikan temperature sebanyak 130⁰F apabila dihubungkan dengan long run dari pipa.

Paper asli Liang-Chaun Peng dapat dibaca di http://www.pipestress.com/papers/UnderGrd-2.pdf

Horizontal Directional Drilling

The Horizontal Directional Drilling (HDD) Industry has experienced so much growth in the past two decades that HDD has become commonplace as a method of installation. One source reported that the number of units in use increased by more than a hundredfold in the decade following 1984. This growth has been driven by the benefits offered to utility owners (such as the elimination of traffic disruption and minimal surface damage) and by the ingenuity of contractors in developing this technology. To date, HDD pipe engineering has focused on installation techniques, and rightfully so. In many cases, the pipe experiences its maximum lifetime loads during the pullback operation.

Horizontal Directional Drilling Process

Knowledge of the directional drilling process by the reader is assumed, but some review may be of value in establishing common terminology. Briefly, the HDD process begins with boring a small, horizontal hole (pilot hole) under the crossing obstacle (e.g. a highway) with a continuous string of steel drill rod. When the bore head and rod emerge on the opposite side of the crossing, a special cutter, called a back reamer, is attached and pulled back through the pilot hole. The reamer bores out the pilot hole so that the pipe can be pulled through. The pipe is usually pulled through from the side of the crossing opposite the drill rig.

Pilot Hole

Pilot hole reaming is the key to a successful directional drilling project. It is as important to an HDD pipeline as backfill placement is to an open-cut pipeline. Properly trained crews can make the difference between a successful and an unsuccessful drilling program for a utility. Several institutions provide operator training programs, one of which is University of Texas at Arlington Center for Underground Infrastructure Research and Education (CUIRE). Drilling the pilot hole establishes the path of the drill rod (“drill-path”) and subsequently the location of the PE pipe. Typically, the bore-head is tracked electronically so as to guide the hole to a pre-designed configuration. One of the key considerations in the design of the drill-path is creating as large a radius of curvature as possible within the limits of the right-of-way, thus minimizing curvature. Curvature induces bending stress and increases the pullback load due to the capstan effect. The capstan effect is the increase in frictional drag when pulling the pipe around a curve due to a component of the pulling force acting normal to the curvature. Higher tensile stresses reduce the pipe’s collapse resistance. The drill-path normally has curvature along its vertical profile. Curvature requirements are dependent on site geometry (crossing length, required depth to provide safe cover, staging site location, etc.) But, the degree of curvature is limited by the bending radius of the drill rod and the pipe. More often, the permitted bending radius of the drill rod controls the curvature and thus significant bending stresses do not occur in the pipe. The designer should minimize the number of curves and maximize their radii of curvature in the right-of-way by carefully choosing the entry and exit points. The driller should also attempt to minimize extraneous curvature due to undulations (dog-legs) from frequent overcorrecting alignment or from differences in the soil strata or cobbles.

General Guidelines

The designer will achieve the most efficient design for an application by consulting with an experienced contractor and a qualified engineer. Here are some general considerations that may help particularly in regard to site location for PE pipes:

1. Select the crossing route to keep it to the shortest reasonable distance.

2. Find routes and sites where the pipeline can be constructed in one continuous length; or at least in long multiple segments fused together during insertion.

3. Although compound curves have been done, try to use as straight a drill path as possible.

4. Avoid entry and exit elevation differences in excess of 50 feet; both points should be as close as possible to the same elevation.

5. Locate all buried structures and utilities within 10 feet of the drill-path for mini-HDD applications and within 25 feet of the drill-path for maxi-HDD applications. Crossing lines are typically exposed for exact location.

6. Observe and avoid above-ground structures, such as power lines, which might limit the height available for construction equipment.

7. The HDD process takes very little working space versus other methods. However, actual site space varies somewhat depending upon the crossing distance, pipe diameter, and soil type

.
8. Long crossings with large diameter pipe need bigger, more powerful equipment and drill rig.

9. As pipe diameter increases, large volumes of drilling fluids must be pumped, requiring more/larger pumps and mud-cleaning and storage equipment.

10. Space requirements for maxi-HDD rigs can range from a 100 feet wide by 150 feet long entry plot for a 1000 ft crossing up to 200 feet wide by 300 feet long area for a crossing of 3000 or more feet.

11. On the pipe side of the crossing, sufficient temporary space should be rented to allow fusing and joining the PE carrier pipe in a continuous string beginning about 75 feet beyond the exit point with a width of 35 to 50 feet, depending on the pipe diameter. Space requirements for coiled pipe are considerably less. Larger
pipe sizes require larger and heavier construction equipment which needs more maneuvering room (though use of PE minimizes this). The initial pipe side “exit” location should be about 50’ W x 100’ L for most crossings, up to 100’ W x 150’ L for equipment needed in large diameter crossings.

12. Obtain “as-built” drawings based on the final course followed by the reamer and the installed pipeline. The gravity forces may have caused the reamer to go slightly deeper than the pilot hole, and the buoyant pipe may be resting on the crown of the reamed hole. The as-built drawings are essential to know the exact pipeline location and to avoid future third party damage.

http://www.ftsl.itb.ac.id/wp-content/uploads/2012/08/15507007-Diyan-Gitawanti-Pratiwi.pdf 

Pipeline Free Span Mitigation

Surface laid pipelines can experience free-spans due to various reasons; uneven seabed and local scour. If free-spans are long, the vortex induced vibrations (VIV) can cause the pipeline to undergo fatigue damage and severely reduce the pipeline design life.

Free-spans can be rectified by,
• Pipeline Lowering (PL) Method
• Grout/Sand bag placement
• Rock dump placement
The selected method for rectification depend on the pipeline details, location, water depths and cost details.
Source:
http://www.capegroup.net/products-services-46/total-oilfield-pipeline-solutions-50/free-span-assessment-rectification-118

ABOVE WATER TIE IN DAN ANALISIS GLOBAL BUCKLING PADA PIPA BAWAH LAUT

Dalam proses instalasi jaringan pipa bawah laut, tidak selamanya pipa disambungkan satu per satu secara berurutan. Ada beberapa situasi yang mengharuskan pipa yang telah digelar dihubungkan di bagian tertentu. Salah satu metode untuk menghubungkan pipa ini adalah tie in atau pengangkatan pipa. Ketika proses tie in berlangsung, pada pipa terjadi momen lentur yang mungkin saja membuat pipa menjadi leleh (yield). Momen di sini akan mengakibatkan tegangan lentur yang harus diperhatikan juga terhadap tegangan leleh ijinnya. Untuk panjang tali, defleksi yang terjadi akibat gaya tarik tersebut juga harus diperhatikan. Oleh karena itu perlu diperhatikan momen dan panjang tali pada saat pengangkatan pipa. 

Maka diperlukan proses penganalisaan yang tepat dengan memperhatikan standar aturan yang berlaku. Setelah dilakukan penyambungan pipa di atas barge , maka dilakukan penurunan pipa kembali ke seabed . Proses ini dinamakan dengan lowering . Pada saat lowering, pipa mungkin akan mengalami deformasi karena tekanan yang terjadi pada pipa yang disebut global buckling . Nantinya setelah dilakukan analisis penurunan pipa, maka akan dilakukan pengecekan global buckling

Dalam analisis tie in ini, akan digunakan program analisis struktur pada pipa bawah laut sebagai program bantu. Analisis ini dilakukan dengan memasukkan data pipa beserta input gaya dan panjang tali pengangkat pipa (davit) dan akan dilakukan 2 analisis, yaitu analisis pengangkatan ( lifting ) dan penurunan ( lowering) pipa. Untuk analisis pengangkatan pipa, dilakukan dengan dengan mengurangi panjang tali sehingga nantinya setelah beberapa kali langkah pipa akan terangkat hingga ke atas permukaan laut. Sedangkan untuk penurunan pipa, prosesnya hampir sama dengan proses pengangkatan pipa, hanya saja dibalik cara pengerjaannya, yaitu dengan memperpanjang tali pengangkat dan menggeser barge ke samping agar pipa dapat ditarik dan turun hingga ke dasar laut. 

Setelah selesai dilakukan penurunan pipa, maka akan dilakukan pengecekan global buckling untuk menentukan apakah terjadi buckling atau tidak pada pipa. Jika terjadi buckling pada pipa, maka proses tie in harus Diana lisis ulang hingga tidak terjadi buckling

Data yang digunakan dalam analisis tie in adalah seperti yang ditunjukkan pada Tabel 1. Data tersebut didapat dari PT Geocean dimana Geocean berperan sebagai subkontraktor yang melaksanakan tie in.

 

Untuk proses pengangkatan pipa, berikut adalah hasil analisis berupa tabel dan gambar yang ditunjukkan pada Tabel 2 dan Gambar 1 .

 

  Dapat dilihat pada tabel di atas bawah pada keseluruhan proses pengangkatan pipa, tegangan yang terjadi tidak melebihi tegangan yang diijikan (87% SMYS), maka analisis di atas dapat digunakan. Sedangkan uintuk proses penurunan pipa, hasil analisisnya ditunjukkan pada Tabel 3 dan Gambar 2 berikut

 

Pada tabel di atas, tegangan yang terjadi juga tidak melebihi tegangan yang diijinkan. Maka hasil analisis di atas dapat digunakan untuk analisis lebih lanjut. Untuk analisis selanjutnya, yaitu analisis lateral buckling , digunakan tegangan terbesar yang terjadi pada penurunan pipa tahap terakhir sebagai residual force (H)