Fitness For Service

Fitness for Service Defined 

Fitness for Service (FFS) is the pipeline’s ability to operate in a manner that ensures the safety of the people that live and work near pipelines, protects the environment, while dependably transporting natural gas from sources to markets. 

Interstate Natural Gas Association of America (INGAA) members established natural gas pipeline FFS principles similar to those of programs widely used in other industries, such as 

transportation, energy, construction, chemical, nuclear and power generation. 

FFS has been an integral part of consensus standards for pipelines since the mid-1980s, and is now embodied in American Society of Mechanical Engineers’ B31.8 and B31.8S. The Pipeline and Hazardous Materials Administration has incorporated many elements of the consensus standards into the Minimum Pipeline Safety Standards. 

FFS Has Been Applied to Metal Loss/Corrosion Since the 1980s 

Pipeline operators apply a variety of techniques to assess a pipeline segment’s physical condition. In-line inspection (ILI) with high-resolution magnetic flux leakage sensors is used to identify and characterize metal loss. High-resolution geometry sensors are used to identify, characterize and measure deformations in pipelines. Operators use this data to calculate risks and predict pressure failure points. Their calculations account for a generous, built-in safety margin below regulated maximum allowable operating pressure (MAOP). 

Why INGAA Created FFS 

INGAA designed their FFS program to address previously untested pre-regulation pipeline, or pipelines built prior to federal regulations established March 12, 1970. Pre-regulation pipe accounts for approximately two thirds of all onshore natural gas transmission pipelines. 

Starting Point and Timeline 

The FFS program establishes a starting point for evaluation and remediation of pre-regulation pipeline in High Consequence Areas (HCAs) that lack traceable, verifiable and complete test records. Further, the FFS process defines a priority-based process, and includes a timeline for analysis, implementation and completion of the program. 

Evaluation of Pre-Regulation Pipe 

INGAA members designed a decision tree for evaluation of pre-regulation pipeline records to identify any existing gaps. Pipe segments that have had a pressure test to 1.25xMAOP are fit for service subject to 49 CFR 192, consistent with the NTSB recommendation on the PG&E failure in San Bruno. Where traceable, verifiable and complete records are lacking, progressive steps are taken that are incrementally more and more conservative in correlation to the sufficiency of data. This process yields eight possible cases. Each case assigns conservative testing, operatin

Reference:

http://www.ingaa.org/File.aspx?id=18072

WELDING TECHNOLOGY

PPS PIPELINE SYSTEM

Our welding technology optimises welding processes with respect to quality and economy. That means

• Advising during cost estimation and project planning
• Advising and assistance during project execution
• Development and maintaining the qualification of our employees
• Obtaining and, if necessary, extending approvals
• Monitoring welding works and quality assurance on jobsites and in our production shop
• Testing and introducing new welding technologies
• Process checks as to DIN EN ISO 15614-1 for all conventional materials (C-steel with a strength
  of 485 N/mm², austenite / austenite-ferrous materials, heat-resistant steels)
• Deployment of qualified welders with examinstions as to DIN EN 287-1 for usual welding processes, additional operating tests as to DIN EN 1418 for fully mechanical and automatic welding
• Welding of all dimensions, wall thicknesses and usual processes

Orbital welding

Welding pipelines using the TIG orbital process with interior clamping fixtures

• Materials: austenite and austenite-ferrous steels, Bubi-pipes
  (Duplex-Inliner, close-fit, in C-steel pipe)
• Visual assessment of the root with a camera integrated with the clamping fixture
• Cooling the weld seam with critical intermediate temperatures
• Dimensions up to DN 250 x 4.5 mm without welding filler material, DN 250 x 9.0 mm with filler material,
  Bubi-pipes with dimernsions up to DN 200 x 14.0 mm (3.0 mm inliner)    

MAG STT welding - manual welding

Welding of pipes using the MAG-STT process (soft tension transfer)

• Welding the root pass with large wire und impulse method, filling and final passes with metal powder filler wire in spray arc
• Materials with a strength of up to 460 N/mm², dimensions from DN 200 to DN 750, wall thicknesses from 10.0 - 35.0 mm
• Premium quality weld joints due to very uniform heating

Partial mechanical welding of large pipes

Pipelines or pipelines with combined E-manual for root/hot pass and MAG (full wire) for filling and final passes with partially mechanised pipeline welding equipment.
Welding the root STT with large wire and MAG (full wire) for filling and final passes using partially mechanised pipeline welding units.
The focus is on producing welded connections that fulfil special requirements while considering the optimum use of material and the optimisation of the welding speed with MAG and TIG orbital welding.

• Materials: Ferrous materials incl. thermally mechanically treated fine-grain construction grade steel
• Pipe dimensions: 16" (406.4 mm) to 64" (1625.6 mm)
• Application in shop and jobsite production

Welding stainless steel

1. Double-wall basin for cutting oil with leak monitoring:
   Holding capacity: 200 m³
   Material: 1.4571
   Client: Wintershall AG, Barnstorf
2. Enhanced Oil Recovery Ölfeld Bockstedt
   Installation of the steel construction, installing the container, systems and pumps, pipeline installation, insulation work, commissioning and trial operation of the plant
   Material: 1.4571 and 1.4462
   Client: Wintershall Holding AG, Barnstorf

Titanium welding/Stade

Production and installation of a DN 400 titanium line
corrosion resistance, high strength at a low density (42% lighter than steel).
Client: DOW Deutschland Anlagengesellschaft mbH, Stade

Also our Location in Ilmenau works foremost in the area of optimisation and development of welding technology for pressurised pipes made of high-strength steels – especially with respect to welding technology and welding parameters.
The TÜV certification as to the German AZWV (Accreditation and Authorization Regulation for Education) enables various traning course possibilities such as

• MAG orbital and TIG orbital welding in plant and pipeline construction as to EN 1418
• Training for driving pipe layers 
• Helpers in pipeline constructiion and
• Pipeline construction manager in pipeline and plant construction

Reference:

http://www.pipelinesystems.com/en/company/welding-technology.html

PIPELINE INTEGRITY MANAGEMENT

Center point energy

Pipeline Integrity Management is a process for evaluating and reducing pipeline risks. The Pipeline Safety Improvement Act of 2002 required the federal Pipeline and Hazardous Materials Administration (PHMSA) to develop and issue regulations that address risk analysis and integrity management programs (IMP) for pipeline operators. In 2003, PHMSA finalized the IMP regulations which pipeline operators were required to implement the following year. As a result of these regulations, natural gas transmission companies must conduct baseline evaluations of pipe segments within high consequence areas (HCAs) by the end of 2012. HCAs are defined as areas where a gas pipeline failure would have a significant impact on public safety or the environment.

Integrity Management Program:

CenterPoint Energy has implemented a robust IMP to achieve or exceed the requirements mandated by PHMSA. This program builds on an existing foundation of pipeline safety regulations covering design, construction, testing, operation and maintenance - a foundation that was laid many years ago. CenterPoint Energy’s IMP is required for approximately 180 miles of HCA pipeline segments, but we plan to do more. By the end of 2012, the company expects to have evaluated over 2,500 miles of pipelines - over 10 times the amount required by PHMSA.

Our Integrity Management Program consists of seven main steps:

1. HCA Identification: CenterPoint Energy evaluates population densities each year to determine the HCAs along the pipeline system.
2. Data Integration: The company gathers and integrates information from historical construction documents, pipeline operating history, and pipeline evaluations.
3. Risk Analysis: The company then analyzes individual pipeline segments for exposure to threats as well as the public safety and environmental consequences of a pipeline failure.
4. Evaluation: Using state of the art tools, CenterPoint Energy evaluates the pipeline segments for corrosion, damage or other issues detrimental to the safe operation of the pipeline segment.
5. Repair: The company then investigates and repairs any issues found during the evaluation step to ensure the pipeline continues to operate safely.
6. Minimize Risks: The company utilizes data integration, risk analysis, evaluations and repairs to develop actions that can be taken to minimize or eliminate future damage and/or consequences.
7. Improve: Finally, the company evaluates the IMP for areas of success and looks for other areas on our pipeline system where improvements can be made. We incorporate these improvements into our ongoing safety initiatives and the cycle starts again.

Public Safety:

The ultimate goal of CenterPoint Energy’s IMP is to protect people living, working and playing near our pipelines, as well as protecting the environment surrounding our pipelines. As a direct result of our IMP efforts, CenterPoint Energy has excavated and examined over 2,100 pipeline segments.

• To combat internal corrosion, we ran over 220 cleaning pigs in 2011 to clean our pipelines, used corrosion inhibitors, and monitored internal corrosion using metal probes.
• To reduce external corrosion, we use cathodic protection equipment and routinely take test point readings to evaluate the pipeline’s level of protection. We also perform pipeline coating surveys - so far we have covered 3,100 miles of our system and plan to complete the entire system by 2016.
• To help prevent third party damage we employ pipeline markers, aerial patrols, foot patrols, and right-of-way clearing. In addition, CenterPoint Energy is fully committed to, and participates in, the 8-1-1 Call Before You Dig Program.

Public Awareness:

CenterPoint Energy has a comprehensive Public Awareness program. We dedicate a great deal of time and resources to keeping in contact with both the public and the emergency responders located near our pipelines. Each year we mail hundreds of thousands of information packets to people living near our pipelines. We also have safety meetings with excavation contractors, law enforcement and fire prevention officials. In addition, we send age appropriate educational materials to the schools near our pipelines. It is our goal to partner with the officials dedicated to protecting the public.

Leading Edge:

CenterPoint Energy is a proud participant and supporter of industry efforts to continually improve pipeline safety and reliability. We are a member of Intrastate Natural Gas Association of America (INGAA) and actively participate in the INGAA Integrity Management Continuous Improvement (IMCI) initiative. IMCI has set a goal of zero incidents as one of its guiding principles. Another IMCI goal is to apply integrity management principles on a much larger scale than required by current regulations. CenterPoint Energy supports these INGAA initiatives and participates on IMCI planning teams.

In addition, the company participates in research projects hosted by Pipeline Research Council International, Inc (PRCI). PRCI is dedicated to researching issues and producing solutions that assure safe and reliable pipelines. CenterPoint is a PRCI member company and participates on many PRCI research teams.

CenterPoint Energy believes we are one of the companies leading the pipeline industry to a safer, more reliable future.

Commitment:

CenterPoint Energy is committed to protecting the public and environment. Our dedication to safety is a reflection of our company values: Integrity, Accountability, Initiative and Respect. If you need further information or have additional questions, please contact us at Midstream Pipeline Safety.

Reference:

http://www.centerpointenergy.com/services/pipelines/naturalgassafety/pipelineintegritymanagement/

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 stresses 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. 

Pilot Hole Reaming

The REAMING operation consists of using an appropriate tool to open the pilot hole to a slightly larger diameter than the carrier pipeline. The percentage oversize depends on many variables including soil types, soil stability, depth, drilling mud, borehole hydrostatic pressure, etc. Normal over-sizing may be from 1.2 to 1.5 times the diameter of the carrier pipe. While the over-sizing is necessary for insertion, it means that the inserted pipe will have to sustain vertical earth pressures without significant side support from the surrounding soil.

Prior to pullback, a final reaming pass is normally made using the same sized reamer as will be used when the pipe is pulled back (swab pass). The swab pass cleans the borehole, removes remaining fine gravels or clay clumps and can compact the borehole walls.

Drilling Mud

Usually a “drilling mud” such as fluid bentonite clay is injected into the bore during cutting and reaming to stabilize the hole and remove soil cuttings. Drilling mud can be made from clay or polymers. The primary clay for drilling mud is sodium montmorillonite (bentonite). Properly ground and refined bentonite is added to fresh water to produce a “mud.” The mud reduces drilling torque, and gives stability and support to the bored hole. The fluid must have sufficient gel strength to keep cuttings suspended for transport, to form a filter cake on the borehole wall that contains the water within the drilling fluid, and to provide lubrication between the pipe and the borehole on pullback. Drilling fluids are designed to match the soil and cutter. They are monitored throughout the process to make sure the bore stays open, pumps are not overworked, and fluid circulation throughout the borehole is maintained. Loss of circulation could cause a locking up and possibly overstressing of the pipe during pullback.

Drilling muds are thixotropic and thus thicken when left undisturbed after pullback. However, unless cementitious agents are added, the thickened mud is no stiffer than very soft clay. Drilling mud provides little to no soil side-support for the pipe.

Pullback

The pullback operation involves pulling the entire pipeline length in one segment (usually) back through the drilling mud along the reamed-hole pathway. Proper pipe handling, cradling, bending minimization, surface inspection, and fusion welding procedures need to be followed. Axial tension force readings, constant insertion velocity, mud flow circulation/exit rates, and footage length installed should be recorded. The pullback speed ranges usually between 1 to 2 feet per minute. 

Mini-Horizontal Directional Drilling

The Industry distinguishes between mini-HDD and conventional HDD, which is sometimes referred to as maxi-HDD. Mini-HDD rigs can typically handle pipes up to 10” or 12” diameter and are used primarily for utility construction in urban areas, whereas HDD rigs are typically capable of handling pipes as large as 48”diamter. These machines have significantly larger pullback forces ranging up to several hundred thousand pounds.

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:

• Select the crossing route to keep it to the shortest reasonable distance
• 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
• Although compound curves have been done, try to use as straight a drill path as possible.
• Avoid entry and exit elevation differences in excess of 50 feet; both points should be as close as possible to the same elevation
• Observe and avoid above-ground structures, such as power lines, which might limit the height available for construction equipment.
• 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.
• Long crossings with large diameter pipe need bigger, more powerful equipment and drill rig.
• As pipe diameter increases, large volumes of drilling fluids must be pumped, requiring more/larger pumps and mud-cleaning and storage equipment.
• 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.
• 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
• 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.

Reference: https://plasticpipe.org/pdf/chapter12.pdf

Pipeline Corrosion 

Unprotected pipelines, whether buried in the ground, exposed to the atmosphere, or submerged in water, are susceptible to corrosion. Without proper maintenance, every pipeline system will eventually deteriorate. Corrosion can weaken the structural integrity of a pipeline and make it an unsafe vehicle for transporting potentially hazardous materials. However, technology exists to extend pipeline structural life indefinitely if applied correctly and maintained consistently. 

How Do We Control Pipeline Corrosion? 

Four common methods used to control corrosion on pipelines are protective coatings and linings, 

cathodic protection, materials selection, and inhibitors. Coatings and linings are principal tools for defending against corrosion. They are often applied in conjunction with cathodic protection systems to provide the most cost-effective protection for pipelines. 

• Cathodic protection (CP) is a technology that uses direct electrical current to counteract the normal external corrosion of a metal pipeline. CP is used where all or part of a pipeline is buried underground or submerged in water. On new pipelines, CP can help prevent corrosion from starting; on existing pipelines; CP can help stop existing corrosion from getting worse. 
• Materials selection refers to the selection and use of corrosion-resistant materials such as stainless steels, plastics, and special alloys to enhance the life span of a structure such as a pipeline. Materials selection personnel must consider the desired life span of the structure as well as the environment in which the structure will exist. Corrosion inhibitors are substances that, when added to a particular environment, decrease the rate of attack of that environment on a material such as metal or steel reinforced concrete. 
• Corrosion inhibitors can extend the life of pipelines, prevent system shutdowns and failures, and avoid product contamination. 

Evaluating the environment in which a pipeline is or will be located is very important to corrosion control, no matter which method or combination of methods is used. Modifying the environment immediately surrounding a pipeline, such as reducing moisture or improving drainage, can be a simple and effective way to reduce the potential for corrosion. 

Furthermore, using persons trained in corrosion control is crucial to the success of any corrosion mitigation program. When pipeline operators assess risk, corrosion control must be an integral part of their evaluation.

What Is the Solution? 

Corrosion control is an ongoing, dynamic process. The keys to effective corrosion control of pipelines are quality design and installation of equipment, use of proper technologies, and ongoing maintenance and monitoring by trained professionals. An effective maintenance and monitoring program can be an operator’s best insurance against preventable corrosion-related problems. 

Effective corrosion control can extend the useful life of all pipelines. The increased risk of pipeline failure far outweighs the costs associated with installing, monitoring, and maintaining corrosion control systems. Preventing pipelines from deteriorating and failing will save money, preserve the environment, and protect public safety. 

Reference:

https://www.nace.org/uploadedFiles/Corrosion_Central/Pipeline%20Corrosion.pdf

New automation concept promises to enhance deepwater pipeline integrity

Wendy Laursen

Special Correspondent

DNV engineers have developed the X-Stream concept to improve the viability of gas transport pipelines in deep and ultra-deep water a long distance from shore. Currently, the cost of pipes strong enough to withstand the pressure differential between internal gas pressure and external hydrostatic pressure in deepwater, and the logistics associated with their installation, can make such pipelines uneconomical. Using X-Stream to control internal pressure, thinner pipe can be used, alleviating these challenges without compromising safety or the integrity of the pipeline.

In 2009, Petrobras posed the question to Dr. Henrik O. Madsen, DNV's CEO: three hundred kilometers (186 mi) from shore, in water 3,000 m (9,842 ft) deep, how can associated gas be economically piped to shore so it can be sold rather than just re-injected? This was not just a theoretical question. A solution could enable commercialization of the gas associated with Brazil's presalt oil fields.

"The challenge is to avoid pipeline collapse over hundreds or even thousands of kilometers as a result of loss of internal pressure through a leak or rupture of the pipe during operation," said DNV Project Manager Flavio Diniz.

The dividing line between safe and collapse critical depth indicates the boundary below which the external pressure can compromise the pipeline. (green = safe area, red = collapse critical area)

Madsen was enthusiastic about the challenge. "As the deepwater gas transportation market will experience massive investments and considerable growth in the years to come, new safe and cost efficient solutions are needed," he said.

DNV has a history of involvement in deepwater projects, including the proposed Oman-to-India pipeline; as well as Bluestream, Perdido, and Ormen Lange.

"We have been instrumental in developing and upgrading the safety and integrity regime and standards for offshore pipelines for decades, and today more than 65% of the world's offshore pipelines are designed and installed to DNV's offshore pipeline standard," said Madsen.

In Rio de Janeiro, DNV has a strong technical team that focuses on riser/pipe engineering and risk management. So, Madsen established a team of mostly young engineers, backed by the global expertise of DNV, and set them to work on the question. The solution was to only involve proven technology. Petrobras engineers were enthusiastic partners throughout the project.

X-Stream's inverted high integrity pressure protection system (i-HIPPS) is designed to isolate the deepwater section of a pipeline if internal pressure drops to a critical level.

The breakthrough came with the realization that the concept behind existing high integrity pressure protection systems (HIPPS) could be used to protect against not just high pressures but low pressures as well. HIPPS is a type of safety instrumented system (SIS) designed to prevent over-pressurization of a plant, such as a chemical plant, oil refinery, or pipelines. It will shut off the source of the high pressure before the design pressure of the system is exceeded, thus preventing loss of containment through rupture (explosion) of a line or vessel. Therefore, a HIPPS is considered as a barrier between a high-pressure and a low-pressure section of an installation.

Currently there are about 20 subsea HIPPS around the world. They are used when the flowlines are designed with a lower pressure than the full well shut-in pressure, to avoid overpressure of the flowline. The idea is that if it is acceptable to use a HIPPS to avoid overpressure of a pipeline, it should be equally safe and acceptable to use a HIPPS system to avoid a low-pressure scenario. The inversion of this technology laid the foundation for DNV's X-Stream deepwater piping solution.

It is the need to prevent the pipe from imploding that currently dictates pipe wall thickness. In ultra-deepwater, the wall pipe needs to be extremely thick, and thus can only be manufactured by a limited number of pipe mills. The thick pipes are also heavy to transport and handle; slow to weld and difficult to install; and require extremely thick and costly buckle arrestors. Currently, the number of suitable installation vessels is also limited.

Floating gas facilities are being developed as an alternative. However, floating gas facilities are in many cases not yet field-proven, and are unlikely to be viable for the relatively low gas volumes associated with some oil fields.

X-Stream introduces a new method to deal with the high external hydrostatic pressures of deepwater without relying purely on material thickness to ensure the integrity of the pipeline.

"Fundamental to the solution is the need to protect thinner pipe from collapse during installation, in case of accidental damage and in emergency shutdown scenarios," explained Asle Venås, DNV Pipeline Segment Director. "The idea of an inverted HIPPS system, i-HIPPS, which isolates the deepwater section of a pipeline when internal pressure drops to a critical level, will fulfil this role, enabling pipe walls to be significantly reduced compared with traditional pipelines."

However, risk analysis showed one unlikely but potentially serious danger remaining – that of an internal leak in the i-HIPPS system itself. If this happened, it would mean the pressure drop could not be arrested.

To cover the situation of an i-HIPPS leak, another inversion of existing technology was brought to the system. This time, rather than double block and bleed (DBB) valves being used to relieve high pressure situations, they would be used to prevent pressures dropping to critical levels. An i-DBB provides backup for the containment of the pressure drop by introducing a gel into the enclosure between the i-HIPPS valves in shallow waters. X-Stream, then, consists of a series of automated valves, pressure transducers and autonomous logic controllers to provide an integrated pressure control system for the lifetime of the pipeline.

In a pipeline running to shore from deepwater, the main i-HIPPS system would be located above the water line to ensure easy access for maintenance, inspection, and testing. The collapse critical point for a pipeline is the depth at which the external pressure can compromise the whole pipeline. Below this point, the impact of a pipeline rupture is limited by the ingress of water which holds back the gas in the pipeline. This situation is the same for traditional pipelines.

In the inverted double block and bleed (i-DBB) concept, a viscous substance with a gel consistency is pumped into the closure between the valves to effectively hinder any leaks from the high pressure side, thus ensuring the integrity of the pipeline.

If, however, leakage or rupture of the pipeline occurs above the collapse critical point, at the rig or near the shore, major damage can result since the water pressure is insufficient to contain the gas and therefore the pressure loss. In this case, a secondary set of i-HIPPS valves would close on a pre-determined low pressure signal to isolate the deepwater pipe and ensure that pressure is maintained. Should the i-HIPPS system leak and pressure continue to fall, the i-DBB system would be activated. Further pressure drop would then be prevented by the gel release.

The secondary i-HIPPS system located below the collapse critical point would be activated to contain the de-pressurization. Should this secondary system develop an internal leak and the internal pressure reach a critically low level, a small bleed valve in the i-DBB system would open to the surrounding water so seawater could flood the void between the i-DBB valves and halt pressure loss.

"With i-HIPPS and i-DBB combined, the system immediately and effectively isolates the deepwater pipe if the pressure starts to fall. In this way, the internal pipeline pressure is maintained above a critical, pre-determined level for any length of time," said Diniz.

DNV's innovation, therefore, centers on inverting the well-established HIPPS and DBB systems to prevent too large a pressure differential in the pipeline, and X-Stream meets the strict requirements set for the safety and integrity of existing subsea piping including ISO and DNV-OS-F101. It becomes cost attractive when more than a kilometer of ultra-deepwater pipeline is required. This is because even small reductions in wall thickness make a huge difference in terms of steel volume, welding effort, and installation costs. The exact reduction in wall thickness depends on the water depth, pipe diameter, and actual pipeline profile. Typically for gas pipeline in water depths of 2,500 m (8,202 ft), the wall thickness reduction can be around 25 to 30% compared to traditional designs.

Diniz described a typical scenario for the presalt region where a pipeline runs to shore from water depths of 3,000 m (9,842 ft). Three hundred kilometers (186 mi) of pipe with outside diameter of 0.457 m (18-in.) lays in deepwater and a further 100 km (62 mi) lays in shallow water. If a minimum internal pressure of 200 bar is maintained by X-Stream, pipe wall thickness can be reduced from 25 mm to 17 mm (~1 in. to 0.7 in.) – a 32% reduction. With concrete coating, this could be further reduced to 15.6 mm (0.6 in.).

The result is a system that would be significantly cheaper than current pipeline technology. The production costs decrease as less steel is required in the construction of the pipe. The reduced wall thickness also means that manufacture using higher grade steel is possible. Installation costs are slashed by the reduced welding times, and the new system also results in increased lay rates without the need for buckle arrestors in some cases. Alternatively, the system could mean a larger diameter pipe can be achieved for the same wall thickness.

In either case, X-Stream reduces the consequences of accidents during installation. The pipe is installed fully or partially flooded with water to prevent collapse. Cleaning and gauging of the pipeline is performed and then it is dewatered and dried for operation. A minimum pressure is maintained in the pipeline during pre-commissioning using produced gas, separated from the water in the pipe by a set of separation pigs and gel. This technology is not new and is already standard practice for several oil companies, but X-Stream provides an additional safety mechanism during deepwater installation operations.

To date, the X-Stream innovation project has been limited to a concept study, and more detailed design will need to be carried out before it is realized on an actual project. DNV is not patenting the concept but intends to work with industry partners to refine the concept, and then act as certification body to approve the detailed design.

"At DNV, we feel confident that huge financial savings can be made for long-distance deepwater gas pipelines without compromising pipeline safety and integrity," explained Madsen.

X-Stream is not a one-off concept limited to Brazil's presalt fields. It is timely to take it to the next stage of development now, he says. New offshore oil and gas fields are being developed in deeper and deeper waters, and export solutions for the gas are critical.

"The technology could be taken around the world," said Madsen. "For instance, it is just as relevant to the pipeline planned between Algeria and Italy for the GALSI project; the South Stream project in the Black Sea; and the SAGE project linking India and the Middle East."

Madsen introduced the X-Stream concept in London this past January, and it has been positively received by offshore companies such as Petrobras, British Gas, Odebrecht Oil and Gas, Saipem, Technip, Subsea 7, and Heerema, among others. For Celso Raposo, Steering Committee Member of the project and head of pipeline services for DNV in South America, the project, coming at a time when Brazil is investing $1 billion/yr in research and development, is an example of the country's growing capacity for successful industry partnerships and technical innovation. He says: "DNV has been a pioneer in pipeline technology and we already work closely with Petrobras providing certification and verification services. The success of this project demonstrates DNV's ability for lateral thinking when it comes to solving practical, real-life problems for the industry."

Reference:

http://www.offshore-mag.com/articles/print/volume-72/issue-8/flowlines-and-pipelines/new-automation-concept-promises-to-enhance-deepwater-pipeline-integrity.html

Pipeline Inspection

In the United States, millions of miles of pipeline carrying everything from water to crude oil. The pipe is vulnerable to attack by internal and external corrosion, cracking, third party damage and manufacturing flaws. If a pipeline carrying water springs a leak bursts, it can be a problem but it usually doesn't harm the environment. However, if a petroleum or chemical pipeline leaks, it can be a environmental disaster. More information on recent US pipeline accidents can be found at the, National Transportation Safety Board's Internet site. In an attempt to keep pipelines operating safely, periodic inspections are performed to find flaws and damage before they become cause for concern.

When a pipeline is built, inspection personnel may use visual, X-ray, magnetic particle, ultrasonic and other inspection methods to evaluate the welds and ensure that they are of high quality. The image to the left show two NDT technicians setting up equipment to perform an X-ray inspection of a pipe weld. These inspections are performed as the pipeline is being constructed so gaining access the inspection area is not problem. In some areas like Alaska, sections of pipeline are left above ground like shown above, but in most areas they get buried. Once the pipe is buried, it is undesirable to dig it up for any reason.

So, how do you inspect a buried pipeline?

Have you ever felt the ground move under your feet? If you're standing in New York City, it may be the subway train passing by. However, if you're standing in the middle of a field in Kansas it may be a pig passing under your feet. Huh??? Engineers have developed devices, called pigs, that are sent through the buried pipe to perform inspections and clean the pipe. If you're standing near a pipeline, vibrations can be felt as these pigs move through the pipeline. The pigs are about the same diameter of the pipe so they range in size from small to huge. The pigs are carried through the pipe by the flow of the liquid or gas and can travel and perform inspections over very large distances. They may be put into the pipe line on one end and taken out at the other. The pigs carry a small computer to collect, store and transmit the data for analysis. In 1997, a pig set a world record when it completed a continuous inspection of the Trans Alaska crude oil pipeline, covering a distance of 1,055 km in one run.

Pigs use several nondestructive testing methods to perform the inspections. Most pigs use a magnetic flux leakage method but some also use ultrasound to perform the inspections. The pig shown to the left and below uses magnetic flux leakage. A strong magnetic field is established in the pipe wall using either magnets or by injecting electrical current into the steel. Damaged areas of the pipe can not support as much magnetic flux as undamaged areas so magnetic flux leaks out of the pipe wall at the damaged areas. An array of sensor around the circumference of the pig detects the magnetic flux leakage and notes the area of damage. Pigs that use ultrasound, have an array of transducers that emits a high frequency sound pulse perpendicular to the pipe wall and receives echo signals from the inner surface and the outer surface of the pipe. The tool measures the time interval between the arrival of a reflected echos from inner surface and outer surface to calculate the wall thickness.

On some pipelines it is easier to use remote visual inspection equipment to assess the condition of the pipe. Robotic crawlers of all shapes and sizes have been developed to navigate the pipe. The video signal is typically fed to a truck where an operator reviews the images and controls the robot.

Reference: 

http://www.ndt-ed.org/AboutNDT/SelectedApplications/PipelineInspection/PipelineInspection.htm

Decommisioning of Pipelines

• Leave in Situ

• Reverse Reeling

• Reverse S-Lay

• Cut and Lift

Reference: http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/OP083.pdf

Pipeline Construction

A pipeline construction project looks much like a moving assembly line. A large project typically is broken into manageable lengths called “spreads,” and utilizes highly specialized and qualified workgroups. Each spread is composed of various crews, each with its own responsibilities. As one crew completes its work, the next crew moves into position to complete its piece of the construction process.

These tasks include:

1. Pre-construction survey

Before construction begins, Williams surveys environmental features along proposed pipeline segments. Utility lines and agricultural drainages are located and marked to prevent accidental damage during pipeline construction. Next, the pipeline’s centerline and the exterior right of way boundaries are staked.

2. Clearing and grading

The pipeline right of way is cleared of vegetation. Temporary erosion control measures are installed prior to any earth-moving activities.

3. Trenching

Topsoil is removed from the work area and stockpiled separately in agricultural areas. Williams then uses backhoes or trenching machines to excavate a pipeline trench. The soil that is excavated during ditching operations is temporarily stockpiled on the non-working side of the trench.

4. Pipe stringing

Individual joints of pipe are strung along the right of way adjacent to the excavated ditch and arranged so they are accessible to construction personnel. A mechanical pipe-bending machine bends individual joints of pipe to the desired angle at locations where there are significant changes in the natural ground contours or where the pipeline route changes direction.

5. Welding and coating pipe

After the stringing and bending are complete, the pipe sections are aligned, welded together, and placed on temporary supports along the edge of the trench. All welds are then visually and radio graphically inspected. Line pipe, normally mill-coated or yard-coated prior to stringing, requires a coating at the welded joints. Prior to the final inspection, the entire pipeline coating is electronically inspected to locate and repair any coating faults or voids.

6. Lowering pipe in and backfilling

The pipe assembly is lowered into the trench by side-boom tractors. The trench is backfilled using a backfilling or bladed equipment; no foreign materials are permitted in the trench.

7. Testing

After backfilling, the pipeline is hydrostatically tested following federal regulations. Test water is obtained and disposed of in accordance with applicable federal, state and local regulations.

8. Restoration

Williams policy is to clean up and restore the work area as soon as possible. After the pipeline is backfilled and tested, disturbed areas are restored as close as possible to their original contours. Restoration measures are maintained until the area is restored, as closely as possible, to its original condition.

Offshore:

Horizontal Directional Drill

Williams proposes to use a horizontal directional drill for the Rockaway peninsula shore approach. This technology will enable Williams to avoid sensitive environmental areas while burying the pipe at depths greater than could be achieved with traditional trenching. Williams is proposing a drill from an onshore site within the Marine Parkway Interchange to an offshore bore exit site, approximately one mile long Lay Barge A lay barge is a complete seagoing plant that allows the pipeline to be assembled and laid continuously along the selected route either on top of the ocean floor or in trenches on the seafloor. When used in conjunction with supporting tugs and an anchoring system, the lay barge can be self-sufficient for months at a time. A system of wire ropes and anchors holds the lay barge on a precise heading to prevent buckling of the pipe as it is laid. The system also propels the barge as anchor lines are reeled in and out. As the barge progresses to the end of the lines, the system is moved ahead by anchor-handling tugs. The completed pipeline is lowered into the water by way of the inclined ramp and a stinger attached to the ramp to guide the pipeline to the seafloor at the proper angle. The pipe curves downward from the stern through the water until it reaches the “touchdown point,” or its final position on the seabed. The pipeline is coated with a high-density concrete to overcome buoyancy so that it can be sunk into place. The entire pipeline will be buried in a subsea trench. The pipeline will be lowered below the seabed along its entire length such that the top-of-pipe is a minimum of three feet below the pre-disturbed natural bottom. Reference: http://co.williams.com/williams/operations/gas-pipeline/pipeline-construction/ http://co.williams.com/williams/operations/gas-pipeline/expansion-projects/transco-expansion-projects/rockaway-lateral-project/offshore-construction/ .

Pipe in Pipe Technology

Installing a second pipeline around the product pipeline isolates the carrier pipeline from the seawater surrounding it and creates a dry chamber around the pipeline that can be engineered to accommodate a range of advanced insulation techniques.

Pipe in pipe systems allow a range of advanced and highly efficient insulation materials to be used to achieve Overall Heat Transfer Coefficients less than 1 W/m2 K. These systems are important components of subsea 

developments where untreated well fluids may have to be transported large distances and wax and hydrate problems have to be managed. 

However, as a result of this efficient insulation, thermal expansion challenges are increased and techniques such as probabilistic analysis, upheaval buckling design, snake lay or cooling spools employed to mitigate high expansion loads.

Insulation Capabilities:

Reference:

http://www.jpkenny.com/SiteCollectionDocuments/PIPE%20IN%20PIPE%20REV%2001.pdf

http://www.deepsea-eng.com/sites/deepsea-eng.com/files/media/DeepSea%20Pipe-in-Pipe%20technical%20presentation.pdf