TD Williamson, Inc.

Pipeline Pigging Q & A

2012-02-27T14:48:00.000-08:00

World Pipelines asked three intelligent pigging companies some pressing questions about technology and techniques for inline inspection - and they answered!

Question 1: As pipelines age they are sometimes prone to time-dependent defects such as stress corrosion cracking, hydrogen induced cracking, and, in some cases, long seam weld cracking. What technology is available or being developed to deal with these issues?

For detection and quantification of cracking, acoustic techniques have become the most widely accepted method. Systems using piezo electric ultrasonic sensors operating in liquid lines have been developed and are in widespread use. More recently, tools using electromagnetic acoustic transducer (EMAT) sensing systems are being developed for service in gas lines, as EMAT does not require a liquid couplant. Supplemental data derived from other sources (coating type, soil condition and pipe vintage) has been shown to provide improved discrimination in identifying features. Additionally, combining data from other forms of inline inspection surveys may aid in discriminating features in an EMAT survey.

Pipeline pigs made their first appearance more than 60 years ago, and ever since, there has been a need to accurately track their movements.

2012-01-23T09:54:00.000-08:00

In basic terms, pig tracking refers to the science (some might say the art) of following a pig’s progress within a pipeline. This can be either a continuous process, or it can be accomplished by locating the pig at sequential predetermined points along the trajectory of the pipeline. Either way, the goal is to be able to know with a high degree of accuracy where a pig is along its intended route at any given point in time.

As pigs have become more sophisticated, so too have the methods used to track them. In the early days, the human ear or a hand on the pipe were the first tracking devises. Later, geophones placed on or near lines routed pig noises to amplifiers and speakers. Even more recently, transmitters have come into wide use, particularly in conjunction with inline inspection (ILI) tools (smart pigs) and in subsea applications. To read more about pipeline pig tracking, click here.

Is Your Company Prepared?

2011-12-15T07:29:00.000-08:00

At TDW, we believe an ounce of prevention is worth a pound of cure. So, we partner with our customers to be operationally ready for the unexpected.

TDW emergency response and operational readiness programs combine planning, preparation and emergency project management with state-of-the-art TDW products and services to assist our partners in preparing for pipeline emergencies.

Based on each customer’s individual needs, we develop a unique emergency response protocol to ensure the availability of all necessary personnel and equipment. Our comprehensive portfolio of fully engineered emergency response products and services includes:

Pipeline Isolation in the Philippines

2011-12-15T07:24:00.000-08:00

With operators eager to ensure that pipeline networks function with minimum interruption, quick replacement of defective valves is important. Shell Philippines Exploration and Production discovered the benefits of SmartPlug® pressure isolation technology from T.D. Williamson Inc. in facilitating a timely replacement of a defective primary emergency shutdown valve on the Malampaya shallow water platform, located in the Philippines.

To read more about this story, click here.

Intelligent Inspection of BPO Line with MFL Technology Facilitates Quick, Accurate Identification of Defects

2011-10-19T09:11:00.000-07:00

NIVELLES, Belgium – October 18, 2011 -- T.D. Williamson SA (TDW), a global provider of pipeline services and equipment, announced the successful completion of an inline inspection (ILI) of a key jet fuel pipeline for the Belgian Pipeline Organisation (BPO). BPO is a military organization, responsible for the operational maintenance of the Central Europe Pipeline System (CEPS) on Belgian and Luxembourg territory.

The inspection of more than 130 kms of pipeline was carried out quickly and efficiently, enabling accurate identification of defects for targeted repair. To inspect the line, TDW used its Magnetic Flux Leakage (MFL) inspection tool, which uses magnets to saturate the pipeline. Sensors oriented within this magnetic field facilitate accurate detection and sizing of internal and external metal loss and other ferrous anomalies.

Click here for more information related to the MFL Technology project press release.

Pipeline Pigging Yields Benefits

2011-10-18T06:42:00.000-07:00

Time and experience have shown pigging a pipeline yields multiple benefits. Cleaning can increase flow efficiency and throughput, as well as control internal corrosion. Inline inspection can help assure that the line is safe to operate. All of these benefits yield increased revenue for the operator. No matter what the line’s function, transmitting natural gas or refined products, or transporting crude, a routine pigging program can help clean the line of internal debris and corrosive elements and improve pipeline integrity through use of inspection tools.

Due to differences in construction, materials and configuration, some lines are inherently easier to pig than others. But no matter what the obstacle, most lines are piggable or can be made piggable. In the case of a “hard to pig” pipeline, more ingenuity and forethought are required. Challenges may include fitting configuration or type, heavy wall pipe, no pig launcher or receiver, valves, dual diameter pipeline, a dirty line or line flow conditions.

What other types of challenges have you had when trying to clean or inspect a pipeline?

Advances in Magnetic Pipeline Inspection

2011-08-05T10:19:00.000-07:00

Today’s pipeline owners and operators are under intensive fiscal and regulatory pressure to ensure that their lines operate safely and efficiently. As a result, the need for accurate, reliable pipeline assessment is greater than ever. Through effective integrity management programmes (IMP), operators continue to discover and mitigate new integrity threats to their systems, and differing technologies must be run in order to locate those various threats. And, as more pipelines are constructed, made piggable and other existing lines are integrated into IMP’s, the ability to inspect them as resourcefully as possible is critical. The days when an inline inspection (ILI) tool was able to yield just one set of data per run in tandem became the standard means of providing operational efficiency to both pipeline operator and ILI service provider.

Has the advancement of multiple dataset concepts reached a level to properly assess pipelines? To find out more about this subject, click here.

How can Double Block and Bleed Technology help with Bitumen, an Extremely Heavy Crude Oil

2011-07-26T10:10:00.000-07:00

Bitumen is essentially extremely heavy crude oil too deep to be conventionally mined and a natural byproduct of decaying organic matter. It is captured through a process known as steam assisted gravity drainage (SAGD). Steam is injected into the ground through one well, heating the bitumen and lowering its viscosity to a point that will allow it to flow by gravity into a second (slightly lower) well for transport back up to the surface. Can a Double Block and Bleed capability in combination with a reduced need for line intrusions provide an alternative to a long term shutdown?

To find out more about this process view our article, "Handling the Heat", published in the July 2011 Hydrocarban Engineering Magazine.

Are Your People Properly Trained?

2011-06-27T06:28:00.000-07:00

With today’s Department of Transportation requirements and the quality and safety priorities being implemented it’s important pipeline operators understand the importance of investing time and money into training programs for their employees. To meet Department of Transportation requirements, training programs must include classroom time, written exams and hands-on performance verifications. Technicians working on Hot Tapping, Plugging and Pipeline Pigging projects need rigorous hands-on training to make sure a safe environment is provided for all.

What type of training programs are you providing for your employees to ensure their safety while on the job?

Company Values Are Important!

2011-06-20T09:02:00.000-07:00

Though there are many values which reflect the culture of TDW, and which drive our operations, three stand out as most prominent:

Initiative: Self-directed behavior -- Sense of urgency in resolving issues -- Explore opportunities to meet customer needs.
Interdependence: Working together as a team -- Employer and employee interaction -- Relationships with customers, suppliers and representatives.
Integrity: Trustworthiness and solid character -- consistent words and walk -- adherence to a code of moral values -- delivery of quality products and services.

T.D. Williamson, Sr. believed and exemplified these values. He built a company whose name is synonymous with excellence.

Today's business is constantly changing, but the core values on which this company was built have stayed the same over the years.

The TDW values system creates a consistent environment that allows each and every employee to make quality decisions that will make a positive impact on the future success of TDW.

What values do you believe help a company to become successfull?

Can In-line Inspection reliably detect long seam weld issues?

2011-05-20T07:50:00.000-07:00

Can In-Line Inspection reliably detect long seam weld issues and if so, with what accuracy relative to the severity of the problem?

Multi-Magnetic Flux Leakage (MFL) Sizing Specification states that in the vicinity of girth welds, seam welds or heat affected zones, depth accuracies degrade by .10T and detection thresholds increase by .10t. To elaborate further, sizing is degraded by 10% in heat affected zones (welds) due to uneven cooling which results in an uneven background gauss level. TDW’s approach for long seam detection involves two magnetic field angles in one inspection tool. The Spiral Magnetic Flux Leakage (SMFL) tool section can clearly see the seam weld and is an excellent way to identify if a metal loss or planar feature is in or near the seam weld. In addition to seam weld detection the multiple magnetic fields enhance each other resulting in a very accurate sizing for long and narrow metal loss features.

Multi-MFL is the tool we recommend to inspect for long seam weld defects. The ability to clearly detect the seam weld and the combined sizing make this the right tool for the job.

What In-line Inspection tool would you consider to inspect for this threat?

The Challenges of Emergency Pipeline Repairs - Which Essential Items Should Be Acquired?

2011-04-29T07:22:00.000-07:00

This is the fourth and final component of the Challenges of Emergency Pipeline Repairs.

Essential Pre-investments

None of the investment items mentioned in the previous posts are off-the-shelf items that can be easily and quickly mobilized in case of an emergency. One can imagine the sense of bewilderment or panic in a real emergency if one does not have any of these items within reach or under one’s immediate control. This is where the real value of an Emergency Pipeline Repair System comes into plain view. As explained in the Introduction, the last step of an EPRS process is to determine which essential investments must be made in advance. With these essential items at his disposal, the operator can confidently face nearly any emergency occurring in the future and be reasonably assured that he can restore his pipeline to operation in the shortest possible time and in the safest manner.

Decision criteria & Essential Pre-Investments

Which items does an operator essentially need? It is not necessary that all the items in each group are acquired in advance and stored in the operator’s premises. The following criteria may help to decide which pre-investments may be required as a minimum:

Risk – What are the main risks? Risk comes in many forms and modes. Knowing the relevant risks will help focus upon the most realistic emergency response scenarios. Therefore:

· Establish the Risk Priority Index impacting the pipeline network.

· Clearly identify the risk scenarios and conceptualize the response scenarios

Time – Which EPRS equipment investments and specialty service Frame Agreements will result in time saving in an emergency response? Time is a factor in damage-finding & damage-assessment, and in the delivery of long lead items, such as flanged connections and structural clamps etc. which can take anywhere from 6 to 9 months, sometimes longer particularly dependent on pipeline size, service (sour or sweet for example), and pressure rating. To save time, the following actions are recommended:

· Establish Framework Agreements for aerial & subsea surveys.

· Build up a spares inventory of Long Lead Items. For example:

o Sufficient line pipe for each critical pipeline.

o Minimum 2 Structural Clamps (=Leak Repair Clamp) per line.

Cost – Where are the main costs in an emergency repair and how can pre-investment contribute to overall cost savings? High cost is to be expected in the intensive offshore repair operations involving subsea diving and other marine spread, specialized equipment and services. Upfront engagement with marine service providers would be an effective cost saving measure. Therefore:

· Establish detail procedures for relevant repair scenarios, and

· Based on the established scenarios, establish Framework Agreements for marine spread & specialist equipment with selected marine contractor(s).

Money – Where is the money in the operations and how to save it? Money is in the pipeline content, the better the inventory is managed with a swift bypass and isolation and a speedy re-commissioning, the more money will be saved.

· Establish Framework Agreement for hot tap & plugging and SmartPlug® services.

· Establish Framework Agreement for DECOMM/RECOMM services and

· Build up an inventory of critical DECOMM/RECOMM spreads.

A Framework Agreement can take many forms and shapes depending on the particular needs at hand and whether the company is to own none of the equipment, or some or all of it. The Agreement could be a full commercial contract, a price agreement, a call-off contract, a retention contract, Blanket Purchase Order, etc. It could be in a Lump Sum format, or time & material, day rates or any combination thereof. Of course the practicalities of fulfilling relatively unknown response and repair circumstances make lump sum contracting difficult to employ in practice. All the above can be worked out in detail in a comprehensive EPRS engineering and GAP analysis study.

EPRS is a Lifetime Commitment for a Pipeline Network

In a way, pipeline incidents are reasonably knowable in advance, like decommissioning of an old production platform. Pipeline operators contemplating investment in new pipeline assets should include EPRS in the CAPEX and OPEX budgeting of their projects over the expected life of the pipeline asset. While EPRS is a relatively new concept in the world of subsea pipelines, recent pipeline incidents occurring around the globe, and the relatively disorganized responses and lack of preparedness to them along with extended downtimes suggest that a new way of thinking and planning is called for in operators’ investment, operating planning and decision-making. With the immediacy and speed of stock and commodities market rattling news events, the shareholders and stakeholders of pipeline operating companies are under increasing pressure to reasonably plan what is knowable and to be prepared to mitigate incidents occurring to their assets over the lifetime of that asset.

An EPRS engineering study is not the end of a full EPRS but it is only Phase I of the process, it merely identifies the gaps in the essential needs. A full Emergency Pipeline Repair System looks as follows:

· Phase I – Definition: Define the scenarios and essential EPRS needs, from risk assessment to shopping list.

· Phase II – Mobilization: Buy the essential items. Purchase the long lead items, service contracts, JVs; procedures; DECOMM/RECOMM spreads; set up the organization & training plans; set up the Base Location.

· Phase III – Maintenance: Maintain the essential items. Maintenance & repair contracts; storage facilities; regular training & readiness drills.

· Phase IV – Intervention: Use the essential items. Develop the right kit system to go out and find the damage and repair it swiftly every time, all the time.

The operator’s real challenges is between what he wants, i.e. to be well prepared to respond and to reinstate the supply to his customers, and what he gets, i.e. to invest heavily into equipment and resources, getting no returns for it, and no desire to manage it as a business. Preplanning, preparation and Partnership with innovative pipeline service providers will help ease the burden of the operator in overcoming these challenges.

What is Driving EPRS in Today’s Business Environment?

Despite the seemingly daunting tasks and deep investments called for in a comprehensive EPRS, the trend among operators is the realization of the need for an emergency response system for the following common reasons:

· Business interruption insurance/underwriting is either going away or premiums are skyrocketing – risk anagement criteria are tightening;

· Negative operating experience from real pipeline downtime is changing conventional wisdom from reactionary to proactive;

· Good business practice suggests that critical pipeline assets need planned EPRS response;

· The interconnectivity of pipeline assets means the consequences of interruption can have wide spread impact;

· Long lead times to respond.

What Are Others Doing?

· A major North Sea player maintains the most sophisticated arsenal of EPRS equipment in the world, along with ~ 30 full time, trained responders;

· An operator in the Gulf of Mexico is customizing an EPRS for its own use in the Deepwater, around its specific critical assets. So are a few others.

· Major gas hub operator was idle for 2 months due to a leaking Flex-joint and is expected to be considering an EPRS now.

· EPRS Clubs are in place in some offshore markets, and they can be effective, but more so in areas where the response is to one failure event, not a multiple loss scenario like a typhoon or hurricane affecting a large offshore area.

· Owners of critical pipelines are increasingly studying and investing in EPRS to various degrees and in various geographical areas (North Sea, Asia Pacific etc).

· Persian Gulf offshore operators of a critical gas gathering and supply pipelines are planning to implement world class EPRS programs with anchor drag focus.

· The concept solution centers on the use of rapid isolation by SmartPlug including the injection through a post-installed wye-piece for a 48” 900# ANSI class pipeline.

In Summary

There is a growing trend among pipeline operators in the global offshore pipeline industry to move away from reactive response to pipeline emergencies and proactively develop or participate in an emergency response system or club driven by recent negative experiences and real downtime pipeline incidents. People learn by watching others live through experiences that could happen to them. For the most expedient response to pipeline emergencies, planning and essential investments must be made in advance – in long lead items, critical repair equipment and marine spread availability to name a few – as these are not necessarily standing ready or off-the-shelf items that can be easily and quickly mobilized in an emergency, let alone cost effectively. It is not always necessary to stock up on all the emergency repair gear and kits; an EPRS engineering study can establish an optimal pre-investment shopping list and procurement strategy. Focusing on realistic pipeline emergency scenarios; on investments that cut long response times; on pre-engagement with marine contractors to control high offshore execution costs; on effective management of pipeline content through investments in bypass and isolation equipment and decommissioning/re-commissioning spreads are increasingly the right approaches to mitigation of pipeline downtime.

Proven capabilities and novel technologies exist today that can be combined into the most responsive repair solutions to match almost any pipeline damage scenario in shallow and deep water, the latter being a field of knowhow immaturity concerning EPRS.

EPRS is a lifetime commitment that should start in the initial investment stage for any new, critical pipeline. Increasingly subsea pipeline operators are joining the industry leaders in understanding EPRS and the long term benefits that such an investment can have.

The Challenges of Emergency Pipeline Repairs - What Kind Of Damage And Which Repair Scenario?

2011-04-11T14:31:00.000-07:00

This is the third of a four part blog post on the Challenges of Emergency Pipeline Repairs.

Damage and Repair Scenarios

After an incident has occurred, a sequence of activities will have to take place as a swift, organized response to restore the integrity of the pipeline:

· Find the damage

· Assess the damage

· Control the pipeline content

· Decommissioning and Re-commissioning

· Fabricate/install the replacement pipe

· Repair the pipeline.

· Return pipeline to safe operation

Find the Damage

Damage can be located based on information provided by intelligent pigging devices such as geometry pigs which locate and quantify dents or ovalities or MFL tools that detect metal loss from gouges. However, the damage itself could rule out the use of intelligent pigs because pipeline flow may already be interrupted for pressure reduction safety reasons or because there could be a real risk of getting them stuck due to unknown pipeline restrictions at the damage site. In this case the primary way to find the location of the damage is by external means, i.e. with vessels towing an ROV sporting all necessary video camera and other equipment, acoustic or side scan survey equipment, supplemented by an aerial survey to detect visual evidence of the damage, such as bubbles and/or oil slicks emanating from the damaged pipeline. Extensive subsea pipeline networks can easily consist of many critical subsea pipelines of long lengths and they are spread over a large geographical area. This calls for the design and deployment of effective protocols for damage-finding and survey systems comprising aerial and marine surveys, supported by well developed procedures to quickly find the damage. Given the size of the ASEAN region the early establishment of a number of coordinated “search hubs” may be needed for the Trans ASEAN Gas Pipeline, each with a dedicated framework agreement with aerial and marine service providers. The key in such search and find surveys is to have quick, ready access to current and accurate pipeline route coordinate and as-built information.

Damage Assessment

Damage assessment is carried out to decide exactly what needs to be done to the pipeline to return it to safe operation. The obvious objective for any assessment is to find a permanent solution, however, due to the complexity of issues involved, it may be necessary to use a phased approach wherein a temporary interim solution is deployed to safely stabilize the situation first, and then a follow-up phase to engineer and deploy the permanent repair solution. In the meantime, the goal of the temporary solution is to enable the pipeline to return to safe operation, either at reduced pressure or, optimally, full pressure and flow. Decisions that could be involved include whether the damaged section needs to be cut out and, if so, how much of the line must be replaced. The decision rests on fit-for purpose criteria as stipulated in the operator’s PIM plan, in compliance with international pipeline codes and local regulatory requirements. Damage assessment can only be accomplished with accurate pipeline condition and physical data that can be modeled so as to provide the basis around which reparation solutions can be designed and practically implemented. Therefore, having existing as-built design and installation information, and accurate physical assessment, metrology, preferably internal and external views of the pipeline are essential. The quicker this information can be accessed, assimilated and applied towards solution options, the sooner the pipeline can return to operation. Typically, there are two main categories of subsea pipeline damage categorization or characterization:

I. Minor damage, such as small piggable dents and pin hole leaks, which generally do not require a cut-out but only a leak/reinforcement clamp; and,

II. Major damage which does require a cut out and replacement, such as non-piggable dents, metal gouges in the pipeline, long snaking displacements due to anchor snag, or a rupture of the pipeline.

The difficulty in assessing damage lies in the fact that, without the aid of internally launched devices, it relies primarily on visual details or measurements obtained by divers or ROV based equipment; however, the information provided is of limited accuracy for a finite element stress analysis. It is believed that there is still some work to do by the industry in this important area of response to come up with more accurate external damage assessment tools and methodologies in order to arrive at the right reparation decisions and optimal cut-out lengths in the shortest timeframe.

Control of the Pipeline Contents

This is about managing the precious commodity inside the pipeline – the gas or the oil/liquid products being transported. What does one do to limit the losses during the emergency response and repair? Stabilization (applying a clamp), bypass, temporary isolation and prompt de-/recommissioning are the means to either keep the product flowing, or retain its value during the repair or to get it flowing again in the shortest possible time.

Decommissioning / Re-commissioning

The subject and application of decommissioning and subsequent re-commissioning of the pipeline is of great importance and must have a prominent place in any EPRS for it to be comprehensive and effective. DECOMM/RECOMM can be and is oftentimes overlooked and is brought in as an after-thought in terms of planning and preparation. However, it has a significant influence on the speed of recovery, return to operation, and the overall integrity of the pipeline. Extensive pre-engineering efforts should be undertaken as part of the EPRS studies in order to have a full grasp of the decommissioning process, in particular in a rupture event, and to decide which necessary spreads, resources, and procedures should be prepared for in advance to ensure a rapid decommissioning and recommissioning of the pipeline when the time comes. Many times the commissioning spreads used during the installation of the pipeline, which can be sizeable in surface area footprint for set up of numerous sets of equipment packages (pumps and/or compressors), could be under much tighter constraints post pipeline start-up and operation. For example, safe work areas may be limited, access to water may be limited, areal footprint may be reduced, along with restrictions on noise, release of gas and other constraints. Some of these constraints may be difficult if not impossible to change during an emergency response and the time to be working through these constraints is not during the emergency itself.

Fabricate/Install the Replacement Pipe Spool

The replacement pipe section or spool is usually prepared and lowered to the seabed by the Diving Support Vessel (DSV). However, there is a limit in length that can be comfortably handled by these vessels, typically up to a maximum of 4 to 6 pipe joints. Unusually long pipeline replacements in case of extensive damage caused by anchor drag, will need to be installed by a heavy lift marine vessel or pipe lay barge installation method. Irrespective of which type marine spread is employed, access to the right equipment at the right time is critical to the speed with which the response and reparation work can be completed and pre-planning and pre-screening such capabilities is important to the overall success of the EPRS.

Repair the Pipeline

There are generally two different repair solutions depending on the size of the damage:

I. No cut-out: or minor damage such as piggable dents and pin-hole leaks; the damaged section does not need to be cut out. The repair consists of simply installing a leak repair/reinforcement clamp around the small damaged part, after cleaning of the pipe surface. The key determinants for not having to cut out the section are generally future operational piggability and operator permanent PIM and pipeline repair philosophy.

II. Cut-out: For major damage such as non-piggable dents or rupture, the damaged section must be cut out and replaced by a new pipe. In this case all the aspects discussed above can take place: hot tapping, isolation, decommissioning and re-commissioning. A repair of this nature involves quite a number of activities both subsea and on the surface, involving a marine spread consisting of a DSV, diving spread, survey vessels and transportation barges, specialized pipeline preparations and repair equipment and pipeline connection equipment.

To illustrate the complexity of the offshore operations, here are a few of the steps that may be required in a typical subsea pipeline repair sequence, each requiring specialized equipment and/or tools and trained and available crews:

· find and uncover (if applicable) the pipeline and the damage site

· perform visual inspections and metrology

· perform desktop engineering analysis and assessment

· develop response and repair plans and procedures including DECOMM if appropriate

· lift the pipeline to gain full round access

· temporarily support the pipeline

· remove the concrete & corrosion coating

· option - install interim/temporary repair clamp

· install fitting and perform hot tap

· install bypass

· install isolation Stopples and/or SmartPlug®

· flush out the hydrocarbons & perform cut out

· perform metrologyprepare replacement spool

· prepare pipe-end

· lower the replacement spool

· connect the pipe ends

· RECOMM the pipeline

· return pipeline to operation

Many of the above activities are the bread-and-butter business of many offshore contractors. We will not go into details here but we will highlight the connection method because it is of considerable importance. There are four generic connection methods available in the market:

· Flanges: a mechanical end connector complete with flange on the subsea pipe end, aligned with a ballflange cum swivel flange welded on the replacement pipe-end. Bolting by divers;

· Structural clamps, simply placed over and gripping the connection at the point where the replacement pipeend is aligned with the existing subsea pipe end. Can be diver-assisted or diver-less using ROV and running tools;

· Hyperbaric welding, by lowering a specially designed welding chamber over the connection point, displacing the water with air and performing a full penetration, butt weld in a dry environment;

· Surface welding, by lifting the two subsea pipe-ends to the surface and welding the replacement joint in between them, and relaying the pipeline.

The latter two methods by welding are the most expensive ones and are not usually applied. Most companies use the flanged connection method or the structural clamp method, which is the fastest and easiest. The structural clamp connection is also the method that is adopted by the Deep Water Response to Underwater Pipeline Emergencies –DW RUPE – the “EPRS club” of the Gulf of Mexico offshore industry. The structural clamp can also be used as a leak repair clamp, so the spare inventory requirements for an EPRS can be minimized.

The Challenges of Emergency Pipeline Repairs - Where is the Risk?

2011-03-31T12:19:00.000-07:00

This is the second of a four part blog post on the Challenges of Emergency Pipeline Repairs.

WHERE IS THE RISK?

1.2 Risk Assessment

The risk of damage lies in the well known modes and mechanisms of subsea pipeline failure which are: corrosion, natural hazards (hurricane/typhoon related, mudslides, earthquakes, seabed current erosion, etc), impact (dropped objects, anchor snags), structural (thermal or pressure expansion or contraction), material (cracks, fatigue), operations (line plugging, deep water SC Riser dynamics) and others. Instinct tells us that corrosion is probably the most frequent and widely occurring failure on the one hand, whereas anchor snag likely causes the most severe damage on the other. Recent experience in the North Sea reveals that anchor drag incidents result in not only physical damage to the pipeline, but also in production shut-in of adjoining fields tied in to the affected pipeline causing huge impact and interruption to many operators for an extended period of time. In another incident the damage to the pipeline was only detected months after it occurred thus jeopardizing the PIM plan. These experiences show that the consequential losses and likelihood of detection are other important factors to be considered in the assessment of risk and planning around an EPRS.

One way of looking at risk is by ranking the failure events as the product of three (3) factors:

· The Severity Index defines how hazardous a failure is likely to be. Ranked from 1 (no discernible effect on product or subsequent processes) to 10 (hazardous effect, safety compromised, noncompliance with government regulations).

· The Occurrence Index defines the likelihood of a failure. Ranked from 1 (failure unlikely, history shows no failures) to 10 (failure almost certain).

· The Detection Index defines the difficulty of detection of a failure. Ranked from 1 (almost certain detection) to 10 (almost impossible to detect failure).

A Risk Priority Index (RPI) defined as Severity x Occurrence x Detection and its value – varying from 1 to 1000 – determines the overall ranking of a failure mode. Interestingly, the RPI also shows that the most frequent causes of incidents are not necessarily the highest ranked ones. Statistics for the Gulf of Mexico (see Figure 1) shows that the highest number of incidents for pipelines and risers over the last decade is dominated by Internal Corrosion at 33% of all incidents, followed by Natural Hazards at 17% and Impact at 12%. A further breakdown of potential causes of failure is shown in Figure 2.

Figure 1 - Incidents of Offshore Pipelines/Risers in the Gulf of Mexico

Figure 2 - Potential Causes of Failure

However, a Failure Mode and Effect Analysis conducted for the Gulf of Mexico incorporating the occurrence, severity as well as detection indices, revealed that the highest RPI is calculated for anchor snag (wet buckle) with 450 points followed by anchor snag (dry buckle) with 360 points (See Figure 3). This is not in the least because of the significant contribution to the RPI made by the high severity index of and high difficulty in detecting an anchor drag event.

Figure 3 - Risk Priority Index (Operational) - Gulf of Mexico

The RPI is an important parameter as it tells which failure events can be anticipated and which repair methods need to be developed to recover from such an unplanned event. In other words, the RPI is one of the key criteria in the decision making process of what to pre-invest in an Emergency Repair Plan. A fully developed RPI for an operator’s specific subsea pipeline assets will determine what causes of failure and failure modes will likely impact their system, and will provide insight and guidance as to what damage consequence, response, and repair scenarios need to be considered for their network.

The Challenges of Emergency Pipeline Repairs

2011-03-28T13:55:00.000-07:00

This will be one of a four part blog post on the Challenges of Emergency Pipeline Repairs.

This next series of blog posts will present an overview of the challenges subsea pipeline operators face concerning Emergency Pipeline Repair Systems (EPRS) and discusses the main criteria for investment decisions to ensure operational readiness for a rapid reinstatement of a pipeline after an emergency event. This is presented against the backdrop of the continuing development of critical subsea pipeline assets delivering energy to end consumers such as the Trans ASEAN Gas Pipeline. These critical energy supply networks form the vital arteries to support vibrant regional economies. Protection of these critical subsea assets against the risk of physical and operational trauma should be of the highest priority to assure the uninterrupted flow through the pipeline network and the energy supply to the customer.

1.1 Risk Management Options
At the centre of every subsea pipeline owner’s operations there is a Pipeline Integrity Management Plan (PIM), the purpose of which is to ensure that the pipeline infrastructure remains “Fit for Purpose”, with due regard for safety and the environment. The objective of a PIM Plan is to ensure that the pipeline network is able to perform the intended function for its design life, and one of its key elements is the management of known risks in order to prevent or mitigate any loss of pipeline integrity, leading to loss of production, customer interruption, and/or expensive repairs. What are the risk management options available to an operator? In generic terms there are three (3) risk management options:

Eliminate the risk through engineered solutions. However, total risk elimination is highly unlikely because of the high costs involved, the human factor and the uncertainty of environmental conditions.
Accept the risk. This is a reactive mode that will ultimately prove to be very costly, not only in dollar terms due to extended loss of production and unplanned repair, but also in terms of potential loss of customers and reputation. This approach is likely to lead to unmitigated exposure of people, assets, and the environment, under the undesirable glare of the media and, ultimately, may lead to possible legal actions against the operator and stakeholders alike.
Reduce the risk, by reducing the probability of occurrence and/or the consequence of failure. In this regard, an Emergency Pipeline Repair System (EPRS) is a risk reduction measure because it reduces the consequence of failure.

With the risk management options defined, why EPRS?

Is Detecting Expanded Pipe Something To Consider?

2011-03-16T12:18:00.000-07:00

Inline inspection (ILI) geometry tools have been a staple of pipeline integrity management programs for many years. Historically, these tools are used to locate dents, ovalities, or other indications of third-party damage, as well as to identify fittings or restrictions that could hinder subsequent pig passage. A part from these traditional types of problems, other issues can also prove problematic in some cases.

For example, in some pipeline joints there is the potential of the pipe diameter becoming inadvertently but permanently increased, either before installation or due to hydro testing or some other in-service condition. While the pipe diameter expansion by itself may not be an integrity threat, it may indicate the material properties of the native pipe may not be as specified, which could apply to other joints with the pipeline as well. Recently, similar integrity threats have arisen related to potential issues with newly manufactured pipe.

In May of 2009, the Pipeline and Hazardous Materials Safety Administration (PHMSA) in the United States issued a safety advisory that some recently milled pipe might have tensile properties below specified minimums. The advisory then suggested a thorough review of pipe specification and deformation tool results should be conducted, to ensure installed pipe was in conformance to American Petroleum Institute (API) 5L requirements. While PHMSA jurisdiction is limited to North America, the potential for pipe of lower-than-specified strength to enter the new constructed market is a global concern. With today’s market for line pipe largely independent of national borders, the need to located affected joints of pipe could arise anywhere in the world.

While geometry ILI tools are traditionally instrumental in detecting pipeline restrictions and damage from external forces, expansion of the pipe diameter from internal forces is a feature that should be considered when inspecting pipe. With the chance of a newly constructed pipeline containing expansions due to below specification pipe material, a properly designed ILI tool and accompanying software are instrumental in accurately identifying and quantifying expanded pipe.

Should the detection of expanded pipe be a part of your pipeline integrity management program?

Reducing Offshore Pipeline Risk by Using an Emergency Pipeline Repair System

2011-03-02T13:04:00.000-08:00

To ensure energy supplies flow without interruption, operators need to protect pipelines from damage. They must respond effectively when the unexpected occurs to their subsea lines, whether it is caused by a passing ships anchor, corrosion or a blockage. Today's operators can substantially reduce risk by establishing an Emergency Pipeline Repair System (EPRS).

An EPRS is an organized plan whose sole objective is to swiftly restore a damaged or inoperable pipeline in order to minimize production downtime. To establish an effective EPRS, potential problems are identified and ranked using a Risk Priority Index (RPI). Optimal repair solutions are set forth that determine the types of investments that must be made in order to fully prepare the operator well in advance of an emergency.

Is the Industry Responding?
Preparing for potential subsea pipeline disruption as a part of a prudent operations contingency plan is gathering momentum. In the North Sea, a major operator maintains a sophisticated arsenal of EPRS equipment and a staff of 30 full-time trained responders. EPRS Clubs are springing up in offshore markets where they must respond to one failure event, as opposed to a multiple loss scenario caused, for example, by a hurricane that affects one area.

Is there a Common Sense Approach?
To mitigate pipeline downtime in the wake of an emergency, operators must identify emergency scenarios, and appreciate the value of investments that will dramatically reduce lengthy response times. By investing in critical equipment, pipeline content can be managed with minimal loss or disruption of flow. Exorbitant costs of emergency marine services can be reined in by simply entering into agreements in advance. These are the essential elements of an EPRS, which aims to reduce loss inflicted by the unexpected. EPRS in and of itself is not difficult. In fact, it is a matter of common sense. It does, however, represent change, and change can be daunting. However, as more and more operators prepare themselves for a safe and prosperous future, they will embrace emergency preparedness as a matter of course. It is only a matter of time.

Does your company have an EPRS strategy?

Innovative Method of Double Block and Bleed

2011-02-16T12:45:00.000-08:00

Whether it's routine maintenance or an emergency repair, work done on a pressurized piping system requires both excellent equipment and proper procedure. The work might take place on a remote section of transmission pipeline far removed from the nearest city, deep below the surface of the ocean, or in the middle of a busy chemical processing plant, but whatever it is, modifications to any active line must be done with the utmost care, and with all appropriate safety measures.

Because they typically contain high concentrates of personnel and large infrastructure investments in a highly volatile environment, hydrocarbon processing facilities such as refineries are increasingly seeking out a double block and bleed option when isolating a section of an active line for repairs or additions without interruption of services. That is, operators are looking for ways to install two barrier surfaces (plus a bleed port for pressure monitoring) between a line’s pressurized contents and any downstream work being performed, such as pipe cutting or welding.

In the past, pipeline operators have used a number of different methods to achieve double block and bleed. For example, two separate valves with a bleed port between them can achieve this. Or, the combination of a valve and a plugging head with a port between them can work, as can the tandem of a plugging head and an isolation plug with a port between them. Many operators have simply used two plugging heads and a bleed port. What all of these methods have in common is the dual barrier concept. Whether the barriers are valves, plugging head seals or combinations thereof, the basic premise is that a second barrier serves as a failsafe for the first.

In response to the to the rising demand for a double block and bleed solution, engineers at TDW have developed the STOPPLE® Train plugging system. The STOPPLE Train plugging system uses components based on a proven technology developed by TDW in the 1950’s and used throughout the world in thousands of plugging jobs. What makes the STOPPLE Train plugging system unique is it links two plugging heads into a “train” capable of providing a double block and bleed function as a means to temporarily block sections of active piping systems.

What methods of double block and bleed have you used in the past?

Do you think the STOPPLE Train plugging system would be a solution to consider for your double block and bleed pipeline isolation needs?

Hard To Pig Pipelines

2011-02-10T14:07:00.000-08:00

There are approximately 600,000 miles of transmission pipeline in the United States today (1.2 Million Globally). Easily pigged pipelines have been inspected, so operators are now faced with inspecting the hard to pig pipelines. Due to differences in construction, materials and configuration, some lines are easier to pig than others. Today all transmission pipeline must be designed to be piggable. A hard to pig pipeline can have one or more of the following challenges:

Fittings (Bends and Tees)
Back-to-Back Fittings (Bends and Tees)
Heavy Wall Pipe
No Pig Launcher or Receiver
Valves (Plug, Gate, Ball, Check)
Dual Diameter Pipeline
Dirty Line
Line Flow Condition (Low vs. High

With good planning by knowledgeable personnel, a great deal of time and money can be saved, both during and after the pigging process.

What challenges do you feel are the greatest when faced with a hard to pig pipeline?