Mitigating Deepwater Pipeline Buckling and Axial Stability

Transient thermal cycling analysis of the flowline system illustrates that if the flowline displaces naturally at crucial seabed features, the initial flowline response is dominated by transient cumulative expansion. During this condition, both ends of the flowline expand independently and increase overall end expansions. A steeply sloping seabed - a contributing component of this phenomenon - inherently causes the flowline to move down-slope, with gravity imposing tension to a hanging flowline.

Recent case study examines ways of improving the stability of high-pressure/high-temperature flowlines

Increased deepwater development over the last decade, together with industry monitoring of high pressure/high temperature (HP/HT) flowlines, reveals the critical nature of global stability in the management of flowline buckling and axial stability of these systems.

Global stability is one of the most important design considerations for a flowline system. This concern represents the potential for a flowline to move either axially along its length, laterally from its installed condition, or vertically causing flowline upheaval.

Large compressive forces induced on a flowline system once operational causes this phenomenon. 

Contributing factors to this phenomenon include seabed terrain, boundary conditions, and operating strategy.

With more than 25,000 mi (40,234 km) of pipeline in the Gulf of Mexico alone, global buckling and axial stability of production flowline systems in water depths between 3,000 ft to 10,000 ft (914 m to 3,048 m) presents an industrywide concern for flowline integrity.

Short flowline systems, generally in a range of 3 to 5 mi (4.8 to 8 km) in length, with the complexity of HP/HT conditions, can translate axially or "walk" as a result of normal operational start-up and shut-down.

More recently, however, flowline systems which incorporate wet insulation and which have comparatively low specific gravity also show a high propensity to walk, even for systems 15 to 20 mi (24 to 32 km) long. INTECSEA has completed a case study on these deepwater systems, identifying specific design aspects of wet-insulated flowline axial stability and associated analysis, and suggesting mitigation options.

Flowline/prpefine systems installed on a steeply sloping seabed compound the problems and underscore industry resolve to remedy mese issues. Fmite element analysis of wet-insulated systems on steep slopes helps quantify the impact of cyclic thermal and pressure loading on a given flowline.

System impacts

The impacts of deepwater buckling and upheaval on deepwater pipelines and flowlines can be significant, including:

• Significant cumulative end expansions greater than 20 ft (6 m) can occur until a system reaches a point of stability
• Flowline system response is characterized by interaction of the seabed slope, flowline expansion, lateral displacement, and effect of the thermal/pressure grathent and thermal cycling
• Selection of a nondirect or somewhat "meandering" flowline route, combined with full-scale, three-dimensional finite element modeling, can mitigate significant end expansions
• Most favorable routing for a deepwater flowline system design may challenge developers, as some seabed features are not avoided easily and can impose significant cost increases on a project
• Flow assurance performance requires that many flowline systems have good thermal properties, or low U-value; i.e., overall heat transfer coefficient Thermal insulation applied on the outside of the flowline can facilitate this performance
• A common system configuration uses wet insulation applied on the outside of the flowline and exposed to the marine environment A single or multilayer coating system of five to seven layers is common
• Low specific gravities of systems can result in a low flowline submerged weight and, consequently, low axial frictional resistance
• Project terrain combined with low systemspecific gravity, and typical production temperature and pressure conditions makes the flowline system susceptible to global lateral buckling as well as axial creep.

The INTECSEA case study addresses these, given the following flowline parameters and conditions: A wet-insulated production flowline system (D/t-17, inlet temperature = 200° F/93° C ) routed across an area of steep slope with a product-filled specific gravity of 1.5 and approximately 20 mi ) in length.

Problem overview

The industry has several deepwater flowline systems routed across challenging seabed features with seabed slopes ranging from 5° to approximately 40°. Notable projects that have negotiated such features include:

• BP's Atlantis project over the Sigsbee Escarpment in the Gulf of Mexico
• Norske Shell's Ormen Lange project over the outer continental shelf in the North Sea
• Medgaz - developed by a five-company consortium - across the Mediterranean Sea from Africa to Europe
• Gazprom/Eni Blue Stream across the Black Sea.

Low-pressure and low-temperature flowlines or export pipelines are comparatively easy to manage because of lower axial force.

A long HP/HT flowline system - fully restrained axially rather than a short flowline - experiences end-expansion and potential for high stresses resulting from lateral displacement at natural seabed features.

In contrast, a partially restrained system - where available seabed friction resistance is not sufficient to balance the compressive force in the flowline - encounters design complexities. Aspects of this system include large transient cumulative expansion and a propensity for the entire system to translate gradually from one end - hot or cold - to the other end - hot or cold - after each cootdown/restart cycle, causing the walking phenomenon.

While walking normally is associated with short flowlines, wet insulated systems ranging up to 20 mi (32 km) long also have these issues. This primarily results from lateral buckles - engineered or natural response - that separate flowline response on either end. In effect, the flowline behaves like a partially restrained system similar to a short flowline.

Analysis of such a system on a flat seabed - including effects of sloped seabed or riser-bottom tension - is a common design approach to quantify flowline walking behavior. Modeling provides a time-efficient solution convergence and reduced computation time and cost.

Limitations to such modeling techniques, however, include seabed undulations, potential flowline spans, irregular bathymetry, and narrow opportunities to identify true flowline response. Selection of the most appropriate design and mitigation requirements is thus limited as well.

For the case study operating conditions, the system is prone to lateral buckling because the compressive force of the flowline is higher than the critical buckling initiation force. The associated flowline route topography is a typical seabed phenomenon in deepwater areas with average grathents ranging from 5° to 10° over a distance of 1 to 3 mi (1.6 to 4.8 km).

Designers can apply a staged approach to assess flowline parameters, with the initial step taking an analytical solution. An initial finite element analysis using two-dimensional finite element modeling, followed with detailed three-dimensional finite element modeling of the actual flowline route, is preferred.

Flowline analysis finite element software (ANSYS) follows in a sequence of load steps, beginning with an as-laid or empty condition and proceeding toward flooded, hydrotest, and operating conditions. The computed analysis includes seabed and flowline profiles, spans, stresses/strains, axial forces, and flowline displacements.

In the case study, water depth ranged between 200 ft (61 m) at the shallow end and 2,500 ft (762 m) on the deep end. The route also had three curves along its length. The average seabed grathent was approximately 8° to 10° across a 3-mi (4.8 km) slope, with the maximum grathent of approximately 20° near the top of the slope.

Preliminary analysis

The analytical solution shows end expansions of 25 ft and 16 ft (7.6 m and 4.9 m) on hot and cold ends, respectively. The two-dimensional analysis shows end expansion of 12 ft and 3 ft (3.65 m and 0.9 m) on hot and cold ends, respectively. The two-dimensional analysis shows that uncontrolled lateral displacement would overstress the pipeline.

Following these preliminary assessments, with its own limitations on predicting the true flowline response, INTECSEA created a full three-dimensional finite element model that includes pipeline route bathymetry and route curves.

This model provides improved global and local predictions of flowline response and associated stresses, expansions. The model also includes pipeline route lay radii, or curves, ranging from 5,000 to 8,000 ft (1,524 to 2,438 m).

More realistic predictions for end displacements are approximately 6 ft and 3 ft (1.8 m and 0.9 m) at the hot and cold ends. Hot-end expansion, compared to two-dimensional assessments, is nearly 50% lower, whereas the cold-end expansion remains more or less unchanged.

Axial force reductions from the previous analysis result from more locations or instances of lateral flowline displacements. This analysis shows a maximum lateral displacement of approximately 40 ft (12 m). These lateral displacements are acceptable because the flowline is not near seabed features that would contribute to its lateral instability.

Reduced stress levels at the displaced flowline sections were confirmed with a local buckling check, per DNV-OS-FlOl. The local buckling unity check along the entire flowline length was within the acceptable limit

Seabed intervention

To evaluate the impact of engineered initiation sites for lateral displacement, INTECSEA included simulated sleepers, orpre-laid pipes, which facilitate flowline displacement. End displacements are 6 ft at hot end and 3 ft at cold end, as predicted by the 3D assessment without pre-installed initiation sites.

The study examined the axial force and lateral displacement along the flowline length. The artificial displacement units induce the flowline to displace at 15 locations; 11 of them similar to the natural displacement locations seen in the previous analysis. These displacements indicate pre-installed sites are not required as long as the flowline displaces naturally.

In some instances, however, intervention systems may be installed to facilitate expected flowline response, as non-engineered lateral displacement may overstress the flowline. A maximum lateral displacement of approximately 35 ft (10.6 m) is observed, and maximum lateral displacements within 5 mi (8 km) from the hot end range from 25 to 30 ft (7.6 to 9 m).

Transient finite element simulations focus on flowline cumulative expansion and whether the entire flowline system would translate independently on both ends, hot or cold.

INTECSEA created an ideal, or best-option, temperature profile for the transient heating cycle and cooled the flowline system uniformly along its length. During cool-down, the effective axial force changed direction from compressive to tensile on a partially restrained system. A component of lay tension also may be included in the effective force.

Transient cycling assessment

The transient cycling assessment captures the transient response when the flowline displaces at specified locations and is especially critical within 3 mi (4.8 km) of either end. Importantly, the assessment shows that seabed intervention improves the overall expansion, which reduces significantly during the transient cycling stage. Controlled flowline displacement at pre-installed and natural seabed locations facilitates this improvement

Transient thermal cycling analysis of the flowline system illustrates that if the flowline displaces naturally at crucial seabed features, the initial flowline response is dominated by transient cumulative expansion. During this condition, both ends of the flowline expand independently and increase overall end expansions. A steeply sloping seabed - a contributing component of this phenomenon - inherently causes the flowline to move down-slope, with gravity imposing tension to a hanging flowline.

This tension becomes increasingly critical if the hot end of the flowline terminates near the bottom of the slope. The flowline length resting on the slope also contributes to the slope of axial force distribution. For this case, flowline expansion more than doubles after only three transient cycles.

Expansions escalate in part because the thermal grathent of heating cycles does not create enough force to displace the flowline; whereas during static full operating condition, thermal grathent displaces the flowline naturally. Heating cycles, therefore, push the flowline axialry on either end.

Because high end expansions - both static and transient - are not a favorable design solution, displacement units along the flowline at specified seabed locations facilitate optimum system performance.

If the behavior of the full 3D assessment including route curves, responds to transient cycles in the similar order of magnitude, final hot end expansion can range from 8 to 9 ft, which is 30% to 50% higher than the predicted 6 ft The cold end expansion will increase to nearly 6 ft.

Both these values are within feasible range for design of end tie-in spools and can be reduced, based on specific design considerations, in consultation with operators. Ideally, a design strategy calls for keeping expansion below 6 ft for most flowlines. End expansions that exceed this goal may require sliding end mechanisms and/or anchoring.

A large component of this transient expansion is accumulated during the first two to three cool-down/heat-up cycles. Subsequent transient expansion gradually tapers to a net relative expansion of zero. At this point, the flowline system effectively exists in a quasi-static zone with the system either stabilizing - indicating no further expansion and axial creep - or transitioning to an axial creep or walking zone.

Based on results of this assessment and engineering judgments from related sensitivity work, the flowline system tends to expand independently during transient temperature cycling and then ceases to expand on both ends after seven to eight full cycles.

Following this stage, the flowline shows signs of stabilization. This study, however, did not eliminate the possibility of axialcreep/walking of the system, because results depended on numerous factors, and are an integral part of such behavior.

The study also suggests that if displacement of a flowline is controlled on or near the slope, designers can further reduce overall cumulative expansion and eliminate axialcreep by optimizing the size and location of an artificial displacement unit Importantly, the study shows flowline system feasibility and that with adequate measures, designers can achieve lateral buckling integrity of the overall system and end tie-in structures.

Recommendations

INTECSEA's assessment of design issues associated with wet-insulated HP/HT flowline systems on a steep slope include:

• Simplified end expansion analysis of these systems can be very conservative and can indicate that a configuration is unfeasible. In some cases, even two-dimensional assessment may not provide true response of the flowline. To accurately assess the response of such system, a complete set of 3D assessments is necessary.
• For a given operating condition, wet insulated HP/HT flowlines - even as long as 20 mi (32 km) - may be susceptible to a large cumulative expansion due to a series of transient* i.e., start-up/cool down, events. Most flowline systems reach the maximum cumulative expansion after two heating cycles. A wetinsulated system on a slope, however, may require five to 10 heating cycles to achieve the maximum cumulative expansion; i.e., stabilizes. This process, though, results in very high end expansions of 10 to 20 ft. The ability to mitigate the cumulative end expansion is critical to a feasible design solution.
• The potential for flowline walking is a central design issue for a HP/HT wet insulated flowline. Designers, however, can mitigate this phenomenon using 3D modeling to generate effective routing of the flowline and to optimize seabed intervention.

Flowline projects that incorporate wet insulation on steep seabed terrain should perform both a design assessment and significant sensitivity reviews of all the relevant parameters. The overall solution is dependent on the flowline system moving with a predictable response, confirmed by analyses. Sensitivity assessments should include: laying pipe within the lay corridor but not on the design centeriine; variability of soil conditions; variability of lay radius; and other known flowline conditions and engineering impacts.

The industry has several deepwater flowline systems routed across challenging seabed features with seabed elopes ranging between 5° to approximately 40°.

For the case study, INTECSEA plotted route profile and relative seabed grathents with average gradlents ranging from 5° to 10°.

A local buckling unity check along the entire flowline length confirmed that the flowline was not overstressed (unity check <1) and was within an acceptable limit for safe operation.

Study of axial force and lateral displacement along the flowline length showed a maximum lateral displacement of approximately 35 ft

Sumber : Kumar, Amitabh; McShane, Brian M. "Mitigating Deepwater Pipeline Buckling and Axial Stability. 28 Januari 2014. http://search.proquest.com/docview/849557963?accountid=31562

Greenstream Validates Temporary Compressors for Deepwater Pipeline Projects

Single station renders wet-buckling contingency, dewatering/drying capabilities

Technical evolution inevitably results in a domino effect for ancillary equipment and processes. The energy industry's continued quest to drill and produce in more severe and remote conditions and environments is one example of this cause-and-effect scenario. The technological development that has allowed exploitation of oil and gas reserves in increasingly deeper waters also has forced construction companies to consider the "wet-buckle" situation and pipeline pre-commissioning operations for gas transportation pipelines.

Weatherford's involvement in the Bluestream pipeline project in the Black Sea presented a wealth of opportunities to design, enhance, and modify systems for a wet-buckle contingency and drying/pre-commissioning of deepwater pipelines. One of the results was the creation of the temporary air compression station (TACS) used for wet-buckle contingency and pipeline pre-commissioning operations of the twin 24-in.pipelines.

The experience and lessons learned with the TACS on Bluestream were translated into work Weatherford performed for the Trans-Mediterranean pipeline, known as Greenstream.

Setting the stage

The Bluestream water depth and the length of the pipeline effectively produced conditions during pipelay that contributed to potential problems such as wet buckling. This condition occurs when water floods the pipelineas it is laid. It results in significant construction delays and increased costs. Wet buckling is most likely to occur during deepwater installation. Although few deepwater projects ultimately require a wet buckle contingency during pipelay, the benefits of having one in place become obvious when compared to the costs incurred to correct the situation post-installation.

Once pipeline installation is complete, pre-commissioning activities follow. Regulators require hydrostatic testing for proving the integrity of deepwater gas lines. Weatherford needed to dewater, clean, dry, and purge nitrogen to ready thepipeline to accept hydrocarbons. The company recognized that the facilities that provide a wet-buckle contingency could also be allocated for the required pre-commissioning operations before introducing hydrocarbons into the pipeline. In addition to assimilating these assumptions and conclusions into their approach, Weatherford realized that during the dewatering phase - or during water evacuation if needed for post wet-buckle recovery - they required additional equipment for overcoming the hydrostatic heads with deepwater pipelines.

The major design criteria for Bluestream, Saipem SpA disclosed, focused on creating as small a footprint as possible and being fuel-efficient to meet detailed operational specifications, which included 64,000 scfm, 3,625 psig, -76° F dew point, and 0.001 ppm oil content. With objectives set and parameters established, Weatherford determined that its combination compressors design could adapt for pipeline use.

Installing the pipeline in these water depths posed a serious risk for wet buckling, and Weatherford specified a contingency at all times during the process. Weatherford provided sufficient compressed air capacity on site and on demand to displace water out of any flooded pipe spools to prevent wet buckling. This approach would enable retrieval of the pipe. Central to this proposal was the use of the same compression spread for dewatering and drying activities during pre-commissioning of the pipelines.

The company took advantage of systems already in place and used them for dual purposes to ensure efficiency. Although previously Weatherford used some elements of the proposed station individually, assembling them into one TACS presented unique challenges, from operating within severe budgetary constraints to delivering a complete system on a tight schedule to a remote location.

Temporary air compression station

The Bluestream solution ultimately saw the construction of a fully stand-alone compression station that incorporated 78 major components and required approximately 40% less space than conventional compressor units. The components consisted of 58 main combination compressors, four feed compressors, eight high-volume air dryers capable of dew points exceeding -76° F, and eight boosters. A Weatherford-engineered combination compressor unit consists of a rotary screw compressor and a horizontal reciprocating compressor, each capable of delivering 1,150 scfm at 2,000 psig. The entire station generates 52,500 bhp (brake horse power) on location. The eight high-pressure boosters, designed around a two-stage horizontal reciprocating compressor, provided an addition-al stage of compression to meet the 3,625-psig final discharge pressure. This overall design fulfilled Saipem's requirement for a system with maximized fuel efficiency and minimized footprint.

Weatherford designed the main combination compressor. But, given the time constraints, the massive task of designing and building all the main compressor units, feed compressors, dryers, boosters, oil filtration units, and auxiliary components, the company had to delegate to an outside engineering team with strong experience in this area. SRC Engineers designed the station and ensured that all of the components operated not only individually, but also as a synergized unit to produce the required flow rates and pressures. Once engineering and construction details were finalized a common design specification, multiple companies fabricated the unit. The first key milestone in this innovative project function was the testing of the TACS on location.

With the formality of testing, delivery, and staging complete, pipelaying operations proceeded. The Saipem 7000 took three to four months to J-lay each line, during which time the station was on standby and ready to operate within 72 hours of a wet-buckle incident. Six operations personnel were on location daily to maintain and run individual units every other day. During pipelay, the site received two call-outs for contingencies, both requiring the use of the station.

Station control, monitoring

The advantage of the TACS lay not only in its conglomeration of individual parts operating as one unit, but also in its use of personnel. During the second call-out, the entire team mobilized within 24 hours. Twelve Russian team members, on site for maintenance duties, operated the station until the standby team arrived because the entire station was tied into the programmable logic controller (PLC).

Using an on-site PLC in a main station control room and unit PLCs on individual operating equipment enabled the equipment to be monitored and provided realtime data on engine parameters, injection line temperatures, flows, and pressures. Availability of real-time data contributed to improvements in Saipem's flow-modeling program. The station PLC was critical to the operational success of the project both for Weatherford and Saipem. The system's main function was to monitor all operating aspects of the station while minimizing personnel requirements and therefore, costs. The operations manager had immediate access to the information from a main control room, which expedited decisions and communication to the team. This integration of systems information and operations ensured no downtime during project operations and provided Saipem with critical data for improving future projects.

Pre-commissioning operations

With pipeline installation complete, Weatherford used its dual-purpose station to dewater and dry the Bluestream line before initiating gas flow. This commissioning operations step begins by flooding the line for hydrostatic pressure testing to 1.5 times its operating pressure. The test reveals leaks and poor welds and establishes value integrity. Once Weatherford tested the line and verified its integrity, the station started, and Weatherford launched the dewatering pig. This process expels all of the water from the entire line. Weatherford chose to use dry air in the dewatering operation to start the drying process, and Saipem decided to continue using dry air because of the inordinate amount of time needed to fill the volume of the pipelinefrom Russia to Turkey.

After dewatering, the company depressurized the line and began the drying process at a low pressure. Weatherford only ran a portion of the station, which depended on drying speed, and the company pumped dry, oil-free, -112° F air into the pipeline to remove the moisture balance. If Weatherford had not dewatered and performed drying procedures properly, the potential for hydrate formation and line blockage would increase significantly. These conditions can produce an inefficient gas flow situation that adversely affects delivery schedules and economic costs and returns.

Each phase of the Bluestream project proved to be unique and required operational modifications. The dewatering phase took approximately 12 days and required the use of the entire station, along with 34 operations personnel on location for two 12-hour shifts. The drying phase used 40% of the main compressors and eight drying units, with the entire system designed to bypass the HP boosters and filtration during this phase.

Within six months of finishing the Bluestream project, Weatherford re-mobilized the TACS for a similar scope of work. This TACS application was for the Trans-Mediterranean pipeline known as the Libya Gas Transmission System (LGTS), or Greenstream. Having unearthed and overcome multiple challenges and problems onsite in Russia, the contingency situations and dewatering and drying process for this gas line ran smoothly.

The TACS used on the project consisted of the same 78 major components, plus 18 coalescing and carbon bed oil-removal filters, flow meters, a centralized remote monitoring system, a fuel pumping and distribution system, and all support facilities (electrical generation, lighting). Weatherford used the same PLC to ensure the smooth running, monitoring, and control of the station.

During installation and pre-commissioning activities, the site received two call-outs for contingency, both requiring the use of the station. Once the team resolved the contingency, Saipem completed the pre-commissioning operations. The company dried the pipeline to the required acceptable dryness criterion and purged and packed it with nitrogen. Saipem introduced hydrocarbon gas in the pipeline soon after the company completed the commissioning process.

Surpassing expectations

Despite never having deployed the TACS as a complete unit before, Weatherford provided a dependable and durable compression station for contingency and precommissioning for two projects in different locales with different conditions. Overcoming problems, addressing challenges, and successfully completing the defined work scope validated the TACS and its self-supporting inventory as an effective solution for deepwater pipelineprojects like Bluestream. Work on the subsequent Greenstream project illustrated the mobility of the TACS and garnered more experience and knowledge of system operations.

TACS provides comfort insurance for pipelay construction companies operating in deepwater, where costs can easily escalate when remedial solutions are not readily available. Not only did the station surpass expectations as a wet-buckling solution, it established itself as a proven synergized package capable of dewatering up to 64,000 scfm and 3,625 psig. This portable station can be deployed globally without the uncertainty of operational capability of last-minute multi-fleet mobilization. As offshore pipeline developments venture into deeper waters, so the TACS, its capabilities, and applications will continue to evolve, meeting new technical challenges and requirements in more extreme conditions and environments.

Sumber : Coleman, Ross; Dilzell, Troy. Greenstream Validates Temporary Compressors for Deepwater Pipeline Projects". 29 Januari 2014. http://search.proquest.com/docview/227311214?accountid=31562

New Deepwater Gas Pipeline Pressure Retention Concept

Dct Norske Ventas (DNV) has developed a new deep water gas pipeline concept that is designed to "significantly reduce the cost of a deepand ultra-deep water gas pipeline while still complying with the strictest safety and integrity regime."

Called X-Stream, it is said to be able to reduce both the pipe wall thickness and time spent on welding and installation compared to deepwater gas pipelines currently in operation.

The company said the exact reduction in the wall thickness depends on the water depth, pipe diameter and actual pipeline profile. Typically, for a gas pipeline in water depths of 2,500 m (8,202 feet), the wall thickness reduction can be 25-30% compared to traditional designs.

Said Dr. Henrik O. Madsen, DNVs CEO who announced the news at a press briefing in London, "It's essential for DNV that the new concept meets the strict requirements of the existing safety and integrity regime."

Madsen added, "DNV has been instrumental in developing and upgrading the safety and integrity regime and standards for offshore pipelines over the past decades. Today, more than 65% of the world's offshorepipelines are designed and installed to DNVs offshore pipeline standard. As the deepwater gas transportation market will experience massive investments and considerable growth over the coming years, new safe and costefficient solutions are needed."

Current deepwater gas pipelines have thick walls and - due to quality and safety requirements - the number of pipe mills capable of producing the pipe is limited. When installing pipelines, the heavy weights are difficult to handle and the thick walls are challenging to weld. The number of pipe-laying vessels for deepwater pipelines is limited.

New offshore oil and gas fields are being developed in deeper waters and export solutions for the gas are critical. New exploration activities are also heading for ultra-deep waters. The distance to shore is increasing. For such fields, the X-Stream concept can represent an alternative to, e.g., floating LNG plants combined with LNG shuttle tankers.

Concept

By controlling the pressure differential between the pipeline's external and internal pressures at all times, the amount of steel and thickness of the pipe wall can be reduced by as much as 25-30% - or even more - compared to today's practice and depending on the actual project and its parameters.

Explains Asie Venas, DNVs Global Pipeline Director, "By using an inverted High Pressure Protection System - i-HIPPS - and inverted Double Block and Bleed valves - i-DBB - the system immediately and effectively isolates the deepwater pipe if the (internal) pressure starts to fall. The internal pipeline pressure is maintained above a critical level for any length of time."

The new concept is described as simple and reliable. During installation, it is necessary to fully or partially flood the pipeline to control its differential pressure. During operation, the i-HIPPS and i-DBB systems ensure that the pipeline's internal pressure can never drop below the collapse pressure - plus a safety margin. In sum - a certain minimum pressure will be maintained in the pipeline at all times.

Says Venas, "It will also be important to maintain the minimum pressure in the pipeline during pre-commissioning. This can be done using produced gas separated from the water in the pipe by a set of separation pigs and gel. This technology is not new to the industry. This method has already been initiated as standard practice by several oil companies."

DNV says a team of skilled engineers, headed by DNV in Rio de Janeiro, Brazil, is behind the X-Stream concept. As with the other DNV concepts launched in 2010 and 201 1, the X-Stream team was asked to think outside the box.

Detailed Design StUl To Come

The DNV study is a concept study, and a basic and detailed design will need to be carried out before the X-Stream concept is realized on a real project. DNV intends to work further with the industry to refine and test the concept.

Concludes Madsen, "I'm pleased to announce the outcome of this innovation project. At DNV, we feel confident that, by further qualifying the X-Stream concept, huge financial savings can be made for long distance,deepwater gas pipelines without compromising pipeline safety and integrity." 

Sumber : "New Deepwater Gas Pipeline Pressure Retention Concept". 28 Januari 2014. http://search.proquest.com/docview/1013848526?accountid=31562

Deepwater Remote Welding Technology for Pipeline Repair and Hot-Tapping

The second paper highlighted from the subsea/flow assurance track addresses flowline and pipelines. Remotely operated dry hyperbaric welding technology has been further developed in recent years and is now becoming the basis for offshore applications both in subsea pipeline repair and hot-tapping technology. This paper outlines the welding technology and the operational systems developed and built to provide an offshore service.

The Pipeline Repair System pool (PRS pool) is a joint development between Statoil and Hydro to provide repair and construction support for the large oil and gas pipeline transportation system on and from the Norwegian Continental Shelf in the North Sea.

The development is funded by a consortium of companies sharing costs in exchange for access to the equipment. In 1987 Statoil was appointed to manage and operate the system and since then a continuous development has been undertaken. Currently PRS is the main repair contingency for approximately 10,000 km of subsea pipelines with dimensions ranging from 8 to 44 in. and water depths down to 600 m. This coverage is now being extended to water depths of 1,000 m as new pipelines come onstream.

The PRS is a comprehensive suite of subsea pipeline construction and repair tools, from isolation plugs and cleaning tools to large manipulation and installation frames, and welding habitat enclosures. The repair methods range from applying support clamps to weakened sections to cutting away damaged sections and replacing with new pipe, joining to the old by either mechanical connections or hyperbaric welding.

The PRS pool has over the last few years also invested in technology for remote hottapping into subsea pipelines, the objective being to provide technology for development projects which the commercial supplier market does not provide on short notice.

In order to achieve this, new unique equipment and welding technology has been developed and qualified with the objective to provide a fully remote operated system without the need for diver-assisted tasks.

Pipeline repair by welded sleeve technique

Traditional hyperbaric welding techniques involve the use of precision machining of the pipe ends and performing butt welds using the GTAW (gas tungsten arc welding) process. This involves precision alignment that can be very demanding (particularly on the second end and especially for large-diameter pipes).

The new approach avoids the need to achieve butt to butt closure and limits the requirement on precision alignment by threading a sleeve (slightly oversized to the pipe) over one end and drawing it back over the two pipe ends to be joined and making the welded join between the end of the sleeve and the pipe using a GMAW (gas metal arc welding) fillet weld. This technique is used on relatively small-diameter onshore pipelines and is part of the tools of the plumbing trade, but it has not been deployed subsea for production pipeline repair.

The development described in this paper is intended for use for repair of up to 44-in. pipelines down to depths in excess of 1,000 m.

Such a method is not covered directly in the existing regulations and codes of practice, although some work has been performed to establish fitness for purpose assessment criteria for sleeve welds, and as a result the project has been working in conjunction with Det Norske Veritas to establish criteria that could eventually form a code of practice.

The authors discuss next the structural design of the welded sleeve against all relevant limit states for maximum loads that can occur and with a safety margin dictated by the use of appropriate safety factors.

The relevant limit states are bursting, global yielding (including buckling), local overstressing/overstraining, unstable fracture (including possible lifetime crack growth) and fatigue. The relevant load cases are pressure testing (after repair), maximum loading during operation and fatigue during operation. It is necessary to consider axial loads that are both tensile-dominated (e.g., for unrestrained pipe segments) and compressive-dominated (e.g., for partially or fully restrained segments). Generally the design is governed by the tensile-dominated maximum loading case in operation.

Remote hot-tapping into subsea pipelines

The basic principle of hot-tapping is to establish a new branch pipeline connection to an existing (mother) pipeline while under full pressure. This involves connecting the branch pipe, including a valve, to the mother pipeline, usually by means of welding or mechanical clamp connections, cutting a hole in the pipe wall by a machine attached to the valve, retracting the cutting head, closing the valve, and disconnecting and recovering the cutting machine. The pipe branch may now be extended by spools and tied-in to a new pipeline in the usual manner. This strategy has been shown to be very cost-effective compared to alternative methods, including shutdown and tie-in at ambient pressure.

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

The primary focus of the remote hot-tap project is the development of a novel design combining the use of a remotely installed mechanical clamp (the retrofit tee), providing the necessary structural strength as well as interfaces toward the isolation valve module and the hot-tap cutting tool, and a saddle-formed "seal weld" made by remotely operated hyperbaric GMA welding inside the branch pipe.

The authors continue to provide a comprehensive overview of the structural design of the hot-tap tee, the hyperbaric GMAW process, welding qualifications, experimental equipment, procedural development, and installation of the welded sleeve and hot-tap tee.

Dry hyperbaric GMAW technology has been formally qualified for water depths down to 1,000 m and demonstrated and verified to a water depth down to 2,500 m.

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

New unique equipment and welding technology has been developed and qualified with the objective to provide a fully remote operated system without the need for diver-assisted tasks.

Sumber : Apeland, Kjell Edvard; Berge, Jan Olav; Verley, Richard; Armstrong, Michael;Woodward, Neil. "Deepwater Remote Welding Technology for Pipeline Repair and Hot-Tapping". 30 Januari 2014. http://search.proquest.com/docview/227301945?accountid=31562

Corrosion Protective Coatings: Rehabilitation of Buried Steel Pipelines

Corrosion-protective coatings have to provide a primary protection, achieved by covering the entire metal surface with a material that prevents the condensation of water on the steel surface. Suitable materials for covering and sealing the whole surface are permanently plastic compounds (petrolatum, butyl rubber) as well as rigid compounds (polyurethane, epoxy resins), which also prevent the interdiffusion or penetration of water and oxygen.

Coal tar and bitumen-based coatings

Coal tar and bitumen coatings are considered early methods, but are still in use in some countries such as India. These coatings can become brittle, resulting in the formation of crevices and cracks, and a significant decrease in adhesion to the steel surface occurs, risking corrosion. Protective current voltages for old coal-tar or bituminous coatings often exceed what is acceptable for an economically efficient cathodic-protection system. High voltage protective currents result in the formation of H2 and therefore increase corrosion.

Two-ply tape systems (PVC and PE tapes)

In most of the cases where tape coatings on pipelines require rehabilitation, two-ply tape systems are the cause. The main reasons for their failure are low-quality material properties, as well as incorrect application.

As PVC is a rather brittle material, tapes made of PVC contain plasticiser agents. During the lifetime of a pipe coating, these plasticisers diffuse out of the PVC carrier film. This results in an embrittlement of the carrier film and a decrease of adhesion when the plasticisers accumulate in the interface between the adhesive and the steel surface. Due to this effect only minor residues of the tape remain on the pipe surface when the pipe is excavated after years of service, and the mechanical and corrosive protection is no longer in place.

PE and butyl rubber-based two-ply tapes, which generally did not suffer from such material drawbacks, failed as well. Two-ply tapes generally contain a carrier film that is coated with an adhesive on only one side. Due to this structure, two-ply tapes can provide certain primary protection against corrosion because of their adhesion to the steel surface, when supported by primer paint. But the sealing properties in the overlapping areas of two-ply tape systems cannot completely prevent the penetration of corrosive agents. In the remaining and clearly defined interface between the layers of a two-ply tape system, micro-channels may exist. This facilitates a possible penetration path for water and oxygen, increasing the probability of corrosion.

Factory or field?

Factory coatings are intended to provide a maximum of mechanical and corrosive protection, while the method of application is not the main focus. Factory coatings can be applied independent of environmental influences and human factors. Field coatings, however, must match the same mechanical and corrosive protection of the corresponding factory coating, and ensure a similar application even under changing conditions on site.

Due to the versatility of application for field-coating systems, worldwide standards for all materials do not exist. German and European standards for corrosion materials are among the highest in the world and applied in several countries. The relevant standards DIN 30672 and EN 12068 for field-coating materials differentiate into three mechanical stress classes (A, B, and C) and three operating temperature classes (up to 30°C, up to 50°C, and high temperatures).

The solution: three-ply tapes

There exists a clear distinction between two-ply tapes and co-extruded self-amalgamating three-ply tapes. The latter contain a carrier film of stabilised PE, which is coated with a butyl-rubber adhesive on both sides. Carrier films of co-extruded three-ply tapes are manufactured with intermediate adhesive layers, ensuring that no clearly defined interface remains between carrier film and adhesive layer. When three-ply tapes are wrapped spirally around a pipe, the adhesive layers self-amalgamate in the overlap areas, forming a homogenous sleeve-type coating without any remaining interface.

Compared to two-ply tapes, no interface or penetration paths remain in the overlapping zones of high-performance, co-extruded three-ply tapes. The outstanding feature of co-extruded three-ply tapes and their layer of butyl rubber is their ability to self-amalgamate in the overlap areas, resulting in a completely sealed, impermeable, and sleeve-type coating.

The test of time

In November 2012, WINGAS – now Gascade Gastransport, a subsidiary of Wintershall and Gazprom – excavated two pipe sections of the 900 mm diameter Sachsen-Thüringen-Erdgas-Anbindungsleitung (STEGAL) transmission pipeline, which was constructed from 1991–1992 in the rocky soils of the Erz mountains in Saxony, Germany.

After 20 years of operation, the joints – covered by a real co-extruded three-ply tape – were still in excellent shape and exceeded the requested values of the guideline EN 12068 stress-class C50. Peel test on sites were taken and values measured up to maximum of 59 N/cm – the corresponding requested value according to EN 12068 stress-class C50 is 10 N/cm.

After the execution of the peel test, a cohesive break in the layers was noticed and the remaining layer showed a thickness of 344 microns.

The tape system used at the STEGAL pipeline was co-extruded three-ply tape DENSOLEN® AS 40 Plus, which was one of the first asymmetrical tape types with a thicker 0.43 mm inner butyl layer to cover the steel substrate better than the symmetrical predecessors.

Coat for your unique project

There are many pipeline rehabilitation systems available in the market of corrosion prevention materials, and all of them may have their advantages and disadvantages. The evaluation of an appropriate rehabilitation system depends on the unique project conditions, as well as the material and on-site requirements, especially taking into account an easy and economical way of applying the system.

For standard temperatures up to +50°C, state-of-the-art co-extruded three-ply tape systems offer the widest range to meet the diverse conditions on site. Those systems can be applied at ambient temperatures from -35°C to +60°C, even under difficult site conditions.

The newly developed system DENSOLEN AS50/R20HT is designed to combine ease of application and economical pricing with excellent mechanical resistance and outstanding corrosion prevention.

Sumber : Schad, Michael; GMBH, Denso; Leverkusen. "Corrosion Protective Coatings: Rehabilitation of Buried Steel Pipelines". 30 Januari 2014. http://pipelinesinternational.com/news/corrosion_protective_coatings_rehabilitation_of_buried_steel_pipelines/083226/