Pipeline Decommissioning

UK pipeline decommissioning provides potential for innovation

Mick Borwell

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 abroad 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.

Reference: 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 prepared, 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: http://www.cepa.com/about-pipelines/pipeline-design-construction/pipeline-construction

Bottom Roughness Analysis

On-Bottom Roughness Analysis and Span Analysis

Depending on the seabed profile, seabed type, loads (self weight and axial loads) and environmental conditions (wave and current induced forces) an on bottom roughness assessment and span analysis is possibly required to identify if any problem areas exist, where spans do not meet the allowable maximum free span criteria.

Maximum static and dynamic allowable free span lengths may be provided to GeoLine for the on-bottom roughness assessment or alternatively we can determine the maximum allowable free spans lengths.

The maximum allowable free span lengths are used as screening criteria to determine areas of critical spans. SAGE Profile finite element software is used to compute the pipeline profile, which is compared with the seabed elevation to determine the span height and span lengths. The computed span lengths are compared with allowable free span length criteria. Environmental loads are taken into account in the analysis.

Modeling the seabed stiffness (bearing capacity) 
is of great importance for results of on-bottom roughness analysis. Non-linear soil springs are
used to model the vertical soil reactions. The soil springs are calculated according to recommended practices  BS 8010, DNV-RP-F105 “Free Spanning Pipelines”.
A sensitivity analysis should be carried out to investigate the affect of varying seabed stiffness on the span lengths.

Reference: http://www.geoline.dk/pipepg7.shtm

Subsea pipeline tie-in/piggable wye tie-in

New direction in piggable wye technology

Piggable wyes have been used extensively in deepwater oil and gas pipeline operations to allow cleaning and inspection pigs and intelligent pigs access through main lines and the laterals that tie into them. Being able to run these state-of-the-art pigs through the wye improves the operating efficiency and the long-term integrity of the pipeline system. Although wyes improve operations on some levels, there are cases when operators need to run pigs counter to the normal flow direction in the lines. This presents no problem in a pipeline with no piggable wyes, but the internal profile at the wye fitting juncture does not permit reverse flow pigging.

Quality Connector Systems (QCS) has developed the Director Bi-Directional Wye to address this industry requirement.

Traditional piggable wye operations

Operators of oil and gas pipelines wage a constant battle against the harmful effects of internal corrosion, paraffin, and condensate accumulation. Commonly accepted practice dictates that the operator run pipeline pigs through the line. The pipeline product flow pushes these cleaning devices through the length of the line. The pig maintains contact with the internal wall of the pipe, pushing hydrates, paraffin, condensate, and other potentially harmful agents in advance of its passage through the pipeline. Corrosive elements are removed from the line at its termination point, enhancing the long-term integrity of the pipeline.

Pigging a single line is a straightforward process, requiring only that the pig be launched from one end and pushed the length of the line using a liquid or gas medium as the propelling force until it is captured in the pig receiver at the end of its journey. However, pigging lateral line tie-in connections requires that the operator pre-plan the installation of a piggable wye fitting in the main line during the construction process. A piggable wye is a Y-shaped fitting that has two inlets, one for each incoming pipeline, and a single outlet that merges the flow of the two converging pipelines. The two lines converge in the Y at an intersecting angle of 30°. This basic wye configuration was originally tested in the 1980s and has proven to be a reliable design.

A piggable wye is a Y-shaped fitting that has two inlets, one for each incoming pipeline, and a single outlet that merges the flow of the two converging pipelines. This view is the ROV-operated option. Click here to enlarge image

For years, the question has been whether it would be feasible to run pigs backward through a wye from the outlet through one of the inlets in a reverse flow pigging application. Until now, the answer has been no.

The internal profile of the wye at the juncture of the two pipelines would likely cause the pig stick in the fitting. Alternatively, if the pig managed to traverse the juncture area of the wye, there would be no way to determine which of the two converging pipelines the pig would flow into.

Bi-directional pigging

A recently developed product now allows pigs to run forward or backward through a wye. The Director Wye has the unique ability to accommodate reverse flow pigging. This new direction in piggable wye technology uses an internal diverter sleeve that is actuated from the exterior of the wye. The diverter can be actuated by an ROV or diver. The internal diverter sleeve rotates within the mainline bore of the wye to direct the pig.

The Director Wye achieves bi-directional pigging through the main line. Click here to enlarge image

The open position permits normal pigging operations that originate through the main line and/or the lateral line that converges into the single main line downstream of the wye. When the internal sleeve of the Director Wye is rotated to the closed position, the barrel of the sleeve closes the access port within the wye from the lateral line to the main line. Conventional pigging can still be conducted through the main line in the closed position, but the diverter sleeve allows a pig to run in the reverse flow direction through the main line as well. With the lateral line bore closed, the pig cannot jam in the juncture of the wye and cannot inadvertently enter the bore of the lateral line.

The Dual Director Wye

The Director Wye had no more entered the market than an operator asked if the design could be modified to permit bi-directional pigging through both the main line and the lateral legs of the wye. The Dual Director Wye accomplishes this feat through the addition of a mirror-image internal diverter sleeve in the lateral leg of the fitting.

The Dual Director Wye permits bi-directional pigging through both the main line and the lateral legs of the wye. Click here to enlarge image

Like its predecessor, the Dual Director can be used as a standard wye with both diverter sleeves in the open position. When the main line diverter is operated to shut off access to the lateral opening, the Dual Director also permits bi-directional pigging through the main line. The differentiating feature of the Dual Director is that if the mainline sleeve closes the main line and the lateral line sleeve is open, bi-directional pigging can be accomplished through the lateral line. The design of the dual internal diverter sleeves and the actuation system is the same for both the Director Wye and Dual Director Wye.

Concept to reality

The Director Wye was initially proposed to a client by means of a hand sketch on a marker board. That rough sketch led to the final product.

An operator planned to commission a pipeline by flushing the water from the line using a pig from the platform to asubsea pig receiver. The plan required that a second operation be performed to remove the subsea pig receiver and to make the final tie-in to a wye on the pre-existing pipeline. This approach entailed several technical and environmental difficulties and was costly in the deepwater environment.

The Director Wye allows the operator to make the subsea connection to the existing pipeline first. Then, the pipeline can be dewatered by opening the valve at the subsea tie-in point and using the pipeline product to push a pre-installed pig in a reverse flow direction through the Director Wye all the way to the platform. Reportedly, this innovative approach will simplify the operational process and reduce commissioning costs for the pipeline.

Future applications

There are other potential applications for the Director Wye, many of which offer benefits to shallow-water and onshore operators. Potential applications for the bi-directional piggable wye include:

• Deepwater tie-backs: Standard practice for deepwater subsea tiebacks dictates the installation of dual pipelines to permit roundtrip pigging of the lines. In many cases, the dual lines are several miles long. The installation of a Director Bi-Directional Wye would enable the operator to install a single line and still be able to pig the system. The pig would enter the wye in the reverse flow direction on its way to the wellhead. The internal director sleeve would be rotated to permit the pig to enter the lateral leg of the wye in a standard flow direction and traverse the wye on its return journey to the platform. Eliminating the redundant flowline reduces capital expense. This procedure also reduces the number of marine risers on the platform to a single riser.
• Permanent reverse flow projects: In certain cases a subsea pipeline system is designed to accommodate a future need to use reverse flow to provide feed gas for offshore operations from an onshore processing facility. In this case, the wye functions as a standard wye as long as the offshore structure can produce enough gas for its operational purposes. Once this is no longer the case, the internal sleeve of the Director Wye can be rotated to permit reverse flow of the product and any required pigging operations to one or more offshore structures.
• Coiled tubing access for deepwater risers: A Director Wye could be installed topside in a marine riser to permit more efficient coiled tubing access. The wye would be installed such that pigging the riser and pipeline could follow the conventional flow. The internal director sleeve would be rotated to close off access to the lateral leg of the wye. When coiled tubing access is required, the internal director sleeve would be rotated to open access to the lateral and permit the installation and withdrawal of the coiled tubing. At the conclusion of the operation, the internal sleeve would be rotated again to close off the tubing access lateral opening to permit pigging of the riser once again.
• Onshore applications: The Director Wye would permit the use of intelligent pigs alternatively through either the main line or the lateral without compromising piggability in either line.

Reference: http://www.offshore-mag.com/articles/print/volume-67/issue-11/drilling-completion/new-direction-in-piggable-wye-technology.html

Pipeline elbow/pipeline bend

Pipe Elbows

8in Schedule 80 pipe (8.63in OD x 0.500) rolled to a 32 inch center-line radius.

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1.5 OD stainless pipe 14ga wall with a 5.25in inside radius.

An "elbow" is defined as a length of pipe with a sharp bend in it. Most commonly elbows have a 90 degree bend, but they could have bends larger or smaller than that and still be referred to as "elbows."

Elbows can be made out of metal, plastic or other materials. Metal elbows are sometimes cast or formed through a variety of processes.  The discussion here will be limited to forming elbows by steel pipe bending of a straight piece of pipe.

Capacity to For Pipe Elbows

Chicago Metal Rolled Products can bend pipe from 3/8in OD to 6in OD through the rotary draw pipe bending process.  Bends as tight as having a center-line radius of only two times the outside diameter of the pipe (a "2D" bend) can be done with no distortion. The company has over 600 die sets that match the OD of the pipe to be bent and the desired radius. Consequently, Chicago Metal almost never has to ask its customers for a tooling charge.

The company can bend from 3/8in OD to 24in OD pipe and tubing through the three-roll bending process.  It operates one of the largest pipe bending machines in the country and has the tooling to perform steel pipe bending of 24in, 20in, 18in, 16in, 14in, 12in, 10in, and 8in pipe as well as all the smaller sizes of pipe.

Pipe Elbows: Value-Added Services

In addition to bending pipe for elbows, the company can drill, flare, cope, and do other ancillary operations. For one customer, Chicago Metal bends aluminum pipe elbows, power washes the bent sections, and stacks the parts on green lumber because the elbows will be heat treated. 

Pipe Elbow Applications 

Applications include process piping, bollards, and ductwork, as well as component parts of equipment and machinery. Chicago Metal has produced pipe elbows to transport water to put out oil well fires during both Iraq wars.

Reference: http://www.cmrp.com/Pipe-Elbows.html

Pipe-in-Pipe

ITP Pipe-in-pipe Flowline

ITP has developed a specific flowline product based on the pipe-in-pipe technique.

A PiP (pipe-in-pipe) is a pipe inserted inside another pipe. The created intermediate annulus can be used to place an insulation material usually known as dry insulation. Indeed this insulation material is protected by the outer pipe from the hydrostatic pressure and from water penetration. PiP generally allow reaching optimized thermal performance compared with wet insulated lines.

ITP pipe-in-pipe flowline solutions are unique since they combine excellent thermal performance with a fast offshore Field Joint (FJ) technique.

On one hand, the ITP solution offers the best thermal performance in the market within the most compact design due to the features of the proprietary IzoflexTM insulation that can be described as follows: - Best as-installed thermal conductivity on the market (7mw/mK). - Mineral structure: silica based, no ageing. - Wide temperature application range (-195 to 900 °C/-320 to 1600°F) - Base material proven in industries such as aeronautics, automotive & nuclear since the 1960's - In operation since 1998 in subsea oil and gas flowlines. - Load bearing insulation: no need for centralizers, the IzoflexTM acts as a continuous centralizer due to its excellent compressive strength. On the other hand, ITP developed a specific Field Joint solution for J-lay and S-lay operations to achieve enhanced layrates and therefore reduce the cost of offshore installation by a factor of at least 2 compared with conventional PiP designs. Please refer to ITP Field Joint section. ITP Pipe-in-Pipes are suited for shallow, deep and ultra deep water as well as HP/HT fields.		Pipe-in-Pipe using ITP swaged end design

1. Pipe-in-Pipes for shallow and deep water applications

ITP systems are particularly well suited for shallow, deep and ultra deep offshore projects: - The pipe in pipe structure accommodates large hydrostatic pressure. - Due to the low thermal conductivity of IzoflexTM, only a thin layer of insulation is required to obtain highly insulated systems, which reduces the outer pipe size and thickness, thus reducing weight and costs (less welding time, less steel). - The compact & efficient insulation allows long tiebacks and long cooldown time. - For J-lay & S-lay, the specific ITP Field Joint (FJ) allows a quick offshore installation (one single weld offshore). - The ITP single/double/quad joint design offer integrated water stop and buckle arrestor every 12/24/48 metres.

Insulation of Quad Joints (48m/158ft) for DeepWater Rosa, Angola

Double Joints assembly yard, Forvie North project	Double Joints ready for collection, Bonga project

2. High Pressure/High Temperature

High Pressure (HP), typically 500bar+ (7252psi+) internal pressure, has a major impact on the flowline design since it can lead to very high wall thicknesses, which makes the fabrication and installation more complex (longer welding times, heavier system ...) High temperature (HT), typically greater than 90°C (194°F) , means that the system operates over a great temperature range between non-producing situations, such as installation, shutdown and the operational case. It implies the use of specific materials to address issues such as fatigue life. ITP offers solutions that comply with HP / HT requirements & constraints: - The insulation, IzoflexTM, can operate up to 900°C (1650°F) without any damage. - The high thermal efficiency of the system allows reducing the flowline thermal variations (increasing fatigue life). - ITP provided the first HP/HT PiP in the North Sea, the (SHELL ETAP project) operating since 1998 at 610bar-155°C/8847psi-311°F. Reference:http://www.itp-interpipe.com/products/pipe-in-pipes/pipe-in-pipes.php

Horizontal directional drilling

Directional Drilling and Pipeline Projects

Sometimes called Horizontal Directional Drilling [HDD]

Allen Watson owns and operates the most technologically-advanced drilling equipment, including maxi to mini-drill rigs with pullback forces from 300te down to 14te. Our extensive range of mud mixing, pumping and recycling systems, mud motors, jet heads, reamers and special tooling combined with our knowledge and experience allows us to successfully complete small, medium and major pipeline projects.

Advantages

• Short, medium or long lengths of pipe can be installed without intermediate pits
• Pipes can be installed either straight or curved to steer clear of obstacles
• By boring underground the working area is confined to points of entry and exit only
• No disruption to road, river or rail traffic and no scarring of the landscape
• Equipment works from surface with no need for deep excavations
• HDD is quick and in many cases has lower overall costs
• HDD is unaffected by surface obstacles
• Can be used to install pipes in changeable ground conditions
• Sea outfalls can be drilled with minimal marine works

Reference: http://www.allenwatson.com/directional-drilling.html

What is Directional Drilling?

Directional drilling provides a safe system of installing pipes, ducts and cables where conventional open cut methods are not permitted, practical, environmentally or economically viable.

Typical Applications

• Steel or polyethylene pipes from 25mmØ up to 1,200mmØ in distances from 25 metres up to 1,500 metres have been successfully drilled under areas such as rivers, estuaries, roads, railways, airports, contaminated landfill sites and Sites of Special Scientific Interest (SSSI).
• Crossings can be for: water, oil, gas, electricity, sewerage, chemicals, communication ducts and outfalls.