A Service Company's Experience with
Pipeline Integrity Management
Derek Storey
Business Development Director, ROSEN Swiss AG
ABSTRACT
Pipeline integrity management is a major focus for the pipeline industry. In recent years interest in this subject has grown enormously due to several factors. Some of the key issues driving greater interest include new legislation, technical developments and the ageing of a fast growing number of pipelines beyond their original design lives.
To clearly understand the needs of integrity management all engineers and managers involved in its application need to be unambiguous in their communications, properly -informed and objective. While this might seem like common sense, experience has shown that these objectives can be surprisingly difficult to achieve. Consequently, both pipeline operators and integrity service companies have not always had an eas y time trying to understand their respective needs and possible solutions. This paper describes some experiences of a service company in providing integrity management support to pipeline operators in different parts of the world. It covers a number of different cases ranging from the specialist development of robotic inspection technologies for hard-to-inspect pipelines, to optimizing a complete integrity management system. The paper uses the combined experiences to recommend a systematic approach to pipeline integrity management and suggest ways of improving its effectiveness in the future.
PIPELINE INTEGRITY MANAGEMENT
A major feature of ROSEN’s 25-year history is the clear understanding that has existed between clients and the company about pipeline inspection needs and capabilities. This has built a foundation of trust that lies at the heart of ROSEN services. However, in-line inspection possesses a unique quality which aids good mutual understanding. That quality is conceptual simplicity. To inspect for corrosion is a major technical challenge but it is not a confusing concept. Integrity management is a different matter.
Worldwide, one of the problems which can be regularly encountered in pipeline integrity management is the lack of a consistent understanding about the subject. This situation results from several different causes, including conflicting semantics, but most of the confusion seems to be caused by a problem at the highest level, the lack of a standard model for integrity management. In place of a standard model there are a very large number of different integrity process descriptions. Virtually all of these are found to be technically correct. They are simply describing the same thing but in different ways. They have been published and pro moted by numerous large groups, including industry organizations, engineering and consultancy companies, service companies and pipeline operators themselves. Consequently the industry as a whole has found it difficult so far to adopt a standard model.
Why is a good standard model of integrity management essential? The answer lies in the simple triangle of Figure 1.
An MIS triangle should be the basis for developing an integrity management system. The concept tells us that we should always be clear about the integrity management needs (M) before we decide on the requirements for the data or information (I) that management will use. The M defines the long-term vision of where we need to go and why. Its design sets the needs for the types, accuracies and time-domains of information (I) needed to support management decision making.
Finally, after the information needs have been defined, the design and construction of the analytical and interpretive system (S) can proceed. The width of each segment is representative of the complexity and commitment involved as we proceed from M to I, then I to S.
The MIS triangle represents a dynamic construction process and the logical sequence of development is from top M to bottom S.
Iterative feedback/feedforward between all three levels is facilitated, but strictly controlled, in the process flow.
The MIS sequence shows us that it would be unwise to design an analytical system without first having a clear definition of the management system it must support. Every pipeline operator has a unique design of management system, and the variety of systems encountered can make life difficult for a service company like ROSEN. However, they are all able to conform to a single model which has been with us for a very long time. That model is the closed loop model of engineering control.
CLOSED LOOP INTEGRITY CONTROL SYSTEM
Figure 2 shows the integrity management control system that has been developed by ROSEN to support communications and understanding both internally and externally w ith its clients. It is based on a conventional control model which has been specially adapted to pipeline integrity control.
The pipeline integrity control loop represents a proven engineering model which can be used to simplify the complexities of pipeline integrity management. The control structure is a closed loop system that incorporates the functions of both dynamic feedback (reaction) and dynamic feedforward (proaction) of pipeline integrity data.
Pipe Wall
The pipe wall is at the center of the control loop representing the entity to be controlled. In this model only the steel of the pipe wall is considered as the central entity because it is the only component that prevents loss of product. Defects in the pipe wall are caused by the effects of the internal and external environments on the pipe wall.
Maintenance Activities
To maintain pipe wall integrity, various maintenance activities are performed on the pipeline. These activities represent the input to the control system. The activities include resources such as effort, money, materials and equipment that are used in maintaining integrity.
Pipe Wall Integrity
The output of the control system is the level of pipe wall integrity actually achieved. The level of integrity can be quantified in various ways including probability of failure analysis, remaining life estimation and reliability assessment.
Settings
Key information like company policy, senior management decisions, resource constraints, regulations, codes and procedures are stored in the Settings. This information is often mandatory and represents what is required in the integrity management process. All Settings are compared with a wide variety of other data in the Processor module as part of the decision making process.
Processor
The Processor of the Control Loop represents a highly advanced analyzer, which can evaluate various data, understand its meaning, make predictions, and take decisions based on a total comprehension of the system’s behavior by comparing data with settings. In the mo del the Processor contains all of the analytical and interpretive processes of the control system. A major feature of the Processor is the extensive use of modeling processes to evaluate integrity. It represents all the people, computers, processes, methodologies and models, which are involved in data analysis and decision- making.
Data – Legacy Database
The Legacy Database is where all pipeline data existing from the current, future and the past of the complete pipeline network is stored. It should be a centralized, multi user capable system based on standards such as PODS and ISPDM, and possess good security, flexibility and expandability to meet all future demands. Data from a wide variety of fields can be stored including data relating to construction, c ommissioning, operations and maintenance. In building a pipeline integrity management system, the population of the Legacy Database with appropriate data is one of the major tasks to be undertaken.
FeedBack Components
Inspection
A direct measure of the pipe wall integrity can be obtained by inspection. In the control diagram this function is contained in the Inspection box where a common kind of survey is In-line Inspection (ILI). Data from inspection is input to the Processor module of the control loop an d represents dynamic feedback data. The Processor assesses the feedback data to make decisions about what feedback actions to take.
Feedback Actor
The output of the Processor represents decisions for action, making use of the various maintenance processes and resources of the control loop input (Maintenance Activities). Actions are then undertaken by the Actor component of the control loop. The Feedback Actor reacts on environmental effects (defects) to repair the pipe wall.
FeedForward Components
Investigation
It is common practice to investigate the environmental conditions that cause pipe wall defects. This is usually done with the intention of taking avoiding actions before pipe wall defects start. Typical investigations are CIPS and DCVG, the investigation of third party interference and investigation of internal conditions which might cause internal defects. Investigation results represent dynamic feedforward data. Data from Environment Investigations are input to the Processor module of the control loop where they are compared against corresponding Inspections data from the pipe wall, and appropriate Settings data. The Processor assesses the feedback data to make decisions about what feedback actions to take.
FeedForward Actor
The Feedforward Actor reacts on the causes of defects to repair or improve the internal and external environments.
Control System Operation
An important feature of the control operation is the relationship between the input and the output. The input ‘Maintenance Activities’ is characterized by resources of different kinds, including effort (people), money, materials and equipment. All of these resources cost money, which is therefore the common denominator of the input. The output of the control system, ‘Pipe Wall Integrity’, can be characterized by reliability.
In accordance with standard control theory, the pipeline integrity control system should ideally operate to achieve a specified output with minimum input. This translates as achieving a defined reliability of the pipeli ne at minimum cost.
MAKING DECISIONS
With the aid of the control loop model we can begin to understand why we have encountered certain difficulties with integrity management in general, more so than with in-line inspection. In the control model, the Inspection of the pipe wall is a task-oriented function. The decision to perform the inspection has already been made by the Processor, which is responsible for analysis and interpretation. An Inspection is therefore the execution of a decision made by an analy sis and decision-making process.
How are decisions made? In the engineering control approach they are based on analytical processes in the Processor component. These analyses investigate whether what is required is actually being achieved. Inspections and Investigations can provide us with data which tells us about what is being achieved. The Settings tell us what must be achieved. If the Settings are ambiguous or inadequate, the control loop operation will be ineffective and inefficient. This would be tru e of any control system which does not know clearly what it should be aiming to achieve. Quite frequently in pipeline integrity management we find that the Settings are not as clear as they could be.
TRUST
ROSEN has always been acutely aware of the import ance of people in all types of technology applications, and we continue to address the issue of people and their roles in the most open, honest way we can. In doing this we bear in mind that we must always remain highly respectful of our clients’ views of organizational structures and people management. Integrity solutions are invariably represented by people plus technology. The inclusion of people means that trust should be the foundation of any integrity management solution.
The issue of trust in integrity management is a very serious one. All of us involved in the field need to have trust in the technologies involved and, of equal importance, have trust in each other. Trust between people is only possible when the
people themselves possess integrity. Th ese features influence the effectiveness with which teams of people can share knowledge and communicate with each other, which in turn influences the efficiency of the entire integrity control system.
Recently, the IBM Institute for Knowledge- Based Organizations (IKO) studied the role of trust in knowledge sharing [1]. Factors such as the strength of the relationship between the knowledge seeker and the knowledge source, the difference between competence-based and benevolence-based trust and the type of knowledge being exchanged were explored. Survey data, including data from one Canadian oil and gas company, was analyzed to determine how trust affects knowledge sharing and how individuals evaluate the trustworthiness of others when seeking knowledge.
The IKO study concluded that the “magic ingredient” that links personal relationships and knowledge sharing is trust.
Two specific types of trust in the knowledge-sharing process were highlighted by IKO: benevolence-based trust and competence-based trust. When most people think about trust, they are typically thinking of benevolence-based trust, in which an individual will not intentionally harm another when given the opportunity to do so. However, another type of trust that plays an important role in knowledge sharing is competence-based trust. Competence-based trust describes a relationship in which an individual believes that another person is knowledgeable about a given subject area.
The IKO study made an important conclusion: It is trust, not the presence of strong ties between people per se, that leads to effective knowledge sharing.
IBM and several other organizations have identified various approaches to promoting trust between people and companies. In parallel with its technical developments, ROSEN continues to monitor developments in this area with the aim of optimizing the efficiency and effectiveness of integrity management processes.
RELATIONSHIPS
Integrity management is usually talked about in a very technical way. Experts in the field usually like to think in terms of ‘solid’ components which can be clearly specified, designed and manufactured for use by people. Yet much experience shows that the greatest problems have been fundamentally human in nature rather than technical.
From the experience of ROSEN it is not possible to overestimate the importance of people in the area of pipeline integrity management. Most of the serious difficulties we have encountered have been human in nature and the application of technical solutions has been relat ively straightforward. However, as a respectful service company, we are limited in our ability to influence the human-related difficulties we may witness in integrity management applications.
Examples of the kinds of situations we may encounter which can lead to difficulties in integrity management processes include: 1. Ambiguous or overlapping areas of authority or
responsibility
2. Competition for limited resources —money, people, power, information
3. Lack of, or inadequate, communication 4. Time pressure
5. Unreasonable standards, rules, policies or procedures 6. Personality clashes
Such situations are real and they should not be ignored if we, as an industry, are to succeed in creating and operating more effective integrity control systems in the future. One way we can improve adverse situations is by implementing new kinds of operational relationships between pipeline operators and integrity service companies.
Improved Relationships for Better Integrity Control
As well as the technical developments that ROSEN is undertaking in several areas of inspection technology, we are also developing new relationships with clients. Traditionally, ROSEN and a client have each supplied technical and human resources to a pipeline revalidation project, operating under conventional company/contractor arrangements. While close cooperation has always been an aim of these traditional arrangements, even greater benefits can be realized through closer integration.
Central to some future projects between ROSEN and its clients will be the crea tion of much closer working relationships between all personnel involved, regardless of their usual positions and responsibilities in the company or department. During an integrated project everyone involved will have the common goal of optimizing the integrity management system of the project pipeline(s). To achieve this goal they will share all relevant data, analytical methods and decision- making processes, and will educate one another to improve all round capabilities and effectiveness. Mutual education and training will represent significant investments for the future for the companies involved. In effect, the solutions for some future integrity improvements will be decided and applied by teams of experts made up from the pipeline operator and key subcontractors. The traditional company/contractor relationship will be replaced by an integrated relationship based on trust and expert teamwork.
The view that a service company has of its client’s needs is very important to the delivered value of a service. In ROSEN we see many of our integrity management contracts as forming key components of customers’ optimization processes. This is because all pipeline operators already possess an integrity control system of some kind, which they inevitably and continuously seek to optimize. Therefore the various services we provide frequently form part of a much bigger optimization effort. This fact has important implications for the way ROSEN looks at
its clients’ needs. In particular it means, as a service company, we must supply only the integrity service components that are requested or required by the customer.
CASE STUDIES
The following two case studies represent examples of ROSEN experience with integrity management services. The control loop provides an ideal fra mework for simplifying and comparing the main features of the different cases as shown in Table 1.
In these case studies ROSEN co-operated in several areas with third party personnel and companies to perform the work.
Case Study 1 – Integrity Management Optimization
Description: Onshore & Offshore Pipeline Network, >20,000 km pipelines, gas & liquids, ages from new to several decades old.
This case study deals with operations within several of the components of the pipeline integrity control system. The client and ROSEN have developed their relationship from an original inspection-oriented approach to a complete system approach after almost ten years experience with the Inspection component (mainly Magnetic Flux Leakage ILI).
This case study has the main goal of optimizing a very large pipeline integrity management system covering more than 20,000 km of pipelines. The optimization of any integrity control system must include making maximum use of the resources that already exist within the pipeline operat or’s company. The pipeline operator had already built up significant technical and managerial investments for pipeline integrity control. Therefore a key feature of any delivered service in this case must be the positive retention and use of the pipeline operator’s valuable investments, where they can make good contributions to the optimization process. This is central to the delivery of maximum value. The operator’s existing investments are quite diverse and include pipeline codes, regulations and integrity control processes, and hardware and software for integrity modeling. The assets also include extremely valuable data such as inspection results from above-ground, ILI and other surveys.
The pipeline operator in this case wants maximum value from maintenance expenditure, rather than simply cost reduction. An important feature of achieving maximum value is the concept of customer independence. The long-term vision of some pipeline operators is that, ultimately, they will be able to operate their integrity control systems independently of any consultants, hardware / software providers or service companies. In addition, when such expert people, wares or services are required, the operator will have free choice in deciding which company to use. This means that all services or products supplied to the operator should be ‘open’ in nature and should not tie the operator to any particular external company.
ROSEN fully supports the concepts of independence, asset retention and open-ness and is designing products and services with this in mind for the case study customer.
In previous years the pipeline operator had substantial success in operating and maintaining its large pipeline network. However, over time significant parts of the network had deteriorated to the point where many maintenance activities were remedial rather than preventative. Consequently, there was an increasing reliance on the Feedback Loop of the control system, based mainly on ILI surveys. This mode of control operation tends to move the input res ources of the control system from one crisis to the next, depriving the preventative Feedforward Loop of many key assets which are needed to remedy the causes of problems.
Usually the key assets which are deprived from preventative duties are people, who are needed to manage all maintenance activities. Big pipeline operators may have enough money available, and the willingness to spend it, but it needs highly trained people who know what they are doing and how best to work together, to manage the expendit ure of it. Technical experts and managers are not usually very large in number even in the biggest operating companies.
A situation where Feedback is the dominant mode of control operation is not necessarily a bad thing, nor is it irrecoverable, but it must be appreciated that the solution is not simply to throw technology and money at the problem. Much more than this is required. In this case ROSEN and the pipeline operator are moving from a company/subcontractor relationship towards an integrated relatio nship that will improve knowledge and understanding on both sides and allow the optimization of the integrity control system.
This case study has a relatively long history, going back about ten years. In this time ROSEN has inspected more than 10,000 km of pipelines in the network and continues to inspect an average of about 3,000 km per year. Most of this work has been performed under conventional company/subcontractor arrangements. As a result of the large volume of inspection carried out ROSEN now possesses a very detailed understanding of what has been found in the client’s pipelines, and how it has changed over time. The future will see better utilization of this valuable knowledge through a more integrated approach.
Control Settings
In most cases Settings are one of the hardest sets of data to obtain for a service company like ROSEN. This is not really surprising because, even when they are well specified, control Settings often represent very confidential information. For example, they usually contain data about financial constraints. Typical Settings should specify the managerial parameters for integrity control, which can include politically sensitive information. Frequently however, ROSEN finds that the Settings of a client are less than well specified, and are uncertainly know even by the operator’s maintenance personnel.
A study of the Settings of this pipeline operator revealed a relatively simple set of criteria. However, it should be noted that
the simplicity of the control parameters supplied to ROSEN may have been due to deliberate limitations on information due to security reasons. Such a situation must be accepted but it does hinder a good understanding by a service company of an operator’s real needs.
Included in the Settings was a zero leak policy. This is an understandable objective for the operator’s higher management, especially when it is stated publicly to give reassurance to the government, the media and members of the public. However, ‘zero leaks’ can make life difficult for the pipeline maintenance personnel who must deliver the goal. In particular, a zero leaks policy does not fit well with risk-based methods of integrity management. These methods work only through the acceptance of a finite failure risk being associated with a pipeline. In reality the risk can never be zero.
Other known Settings of importance were:
•
All pipelines: remaining life >20 years•
Zero leak policy•
Repair pipe to as -constructed specifications•
Need for value rather than cost minimization•
Strong hierarchal management system; authorative•
8 divisions involved in integrity management decisions•
Mainly internal regulations for integrity management•
B31G code for pipe wall defect assessment•
A proactive integrity management system required•
Increasing maintenance res ponsibilities for third party pipelines and need to build more new lines in the existing network.Several of these Settings posed challenges for the integrity control system. One of these was repairing pipe to as -constructed specifications. This criterion meant large numbers of repairs were being made on an, arguably, inappropriate basis, because the existing operations did not require the earlier superior standard. Good engineering practice in this case would have allowed for a change in the repair standard and reduced the required number of repairs, which in turn would have reduced the cost. In addition, easing the work load for maintenance personnel would have allowed more focus on other important areas like preventative maintenance.
A second challenge in the Settings was the involvement of eight company divisions in making integrity management decisions. These included the corrosion department, and inspection, CP, procurement, contracts, finance and IT departments. Each of these departments possessed one or more databases that were deemed to ‘belong’ to the department. Also, the divisions were not all located in the same building and there existed personal differences and hierarchal politics. Consequently, getting almost anything changed was a significant undertaking.
In recent years ROSEN has worked hard with all divisions of the client with the aim of optimizing the pipeline integrity control system. With a patient and structured approach, advances have
been made and they continue to be made to the present time. ROSEN has been involved in supporting or advising on many areas of the integrity control system, including:
•
Inspections – best use of existing pipe wall inspection technologies and development of new ones•
Investigations – requirements for internal and external environmental data•
Settings – most appropriate integrity control rules•
Processor – best analysis practices and procedures; best use of inspection data•
Data storage – best system design; integration of dataObviously, because of its core competences, ROSEN has been able to make the biggest optimization contributions to the inspection needs of the client.
Inspection
ROSEN started providing ILI services to the client in 1994. In order to gain more effectiveness in the Processor operations of the client’s integrity control system, in 2001 the pipeline operator and ROSEN initiated workshop meetings for exchanging information and investigating action on future developments in pipeline inspection. These workshops had no constraints on what should be studied in the client’s control system. However they did concentrate on investigating the development and application of inspection technologies for both piggable and non- piggable pipelines. Among the technologies considered for application have been t he following components.
EMAT Technology
ROSEN has collaborated with some of the world’s leading experts in Electromagnetic Transducer (EMAT) technology to develop an EMAT tool for the inspection of cracks and coatings (Figure 3). Flaw detection using an EMAT is similar to conventional ultrasonic inspection using piezoelectric transducers. An ultrasonic pulse is produced in the pipe wall by an electrical pulse in a wire conductor. The ultrasonic pulse then travels through the pipe wall. If a suitable kind of flaw is present, the pulse interacts with the flaw and a proportion of the pulse energy is reflected back to the receiving EMAT. The ultrasonic echo signal is converted to an electromagnetic signal, which is then recorded.
ROSEN’s EMAT tool has been developed to support SCC inspection of dry gas pipelines, and to inspect for fatigue and other cracks in both liquid and gas lines. It is currently being tested and evaluated. Figure 4 shows a typical scan of axial cracking.
Robotic Inspection Tools
There is no single definition of a ‘robot’. Various descriptions can be found in the literature including:
- machine or device that operates automatically or by remote control
- A machine that makes kinematic decisions
Th e second definition is really more complex than it appears and it is nearer to ROSEN’s definition of the term ‘robot’ than the first definition. There are three important words in the second definition.
The first word, Machine, means that a robot is a mechanical device. This differentiates it from an ‘android’ or other biological creation.
The second important word is kinematic. This means that a robot must have moving parts. Computers programmed with artificial intelligence would not count as robots. Furthermore, the moving parts must be involved in decisions.
The third important word is Decisions. The robot must have the ability to perform a physical task in more than one way and must make decisions as to which paths of motion are the best for performing that task. Therefore, robots evaluate options and make decisions.
By this definition a small, wheeled vehicle that decides on the best way to go around an obstacle is a robot; but the six -axis manipulators found on automobile assembly lines are not. There are as many different types of robots as there are tasks for them to perform. A robot can possess some control by a human operator, sometimes from a great distance. But most robots are controlled by computer, and fall into two categories: autonomous robots and insect robots.
An autonomous robot acts as a stand-alone system, complete with its own computer (called the controller). Insect robots work in fleets ranging in number from a few to thousands, with all fleet members under the supervision of a single controller. The term insect arises from the similarity of the system to a colony of insects, where the individuals are simple but the fleet as a whole can be sophisticated.
Robots are sometimes grouped according to the time frame in which they were first widely used. First-generation robots date from the 1970s and consist of stationary, nonprogrammable, electromechanical devices without sensors. Second-generation robots were developed in the 1980s and can contain sensors and programmable controllers. Third-generation robots were developed between approximately 1990 and the present. These machines can be stationary or mobile, autonomous or insect type, with sophisticated programming, speech recognition and/or synthesis, and other advanced features. Fourth-generation robots are in the research-and-development phase, and include features such as artificial intelligence, self-replication, self assembly, and nanoscale size (physical dimensions on the order of nanometers, or units of 10-9 meter).
Several workers in the field of robotics have developed robotic snakes which mimic a real snake. Some designs resemble an inline inspection tool (Figure 5). For real inspection tasks however the snake design is not the most suitable.
ROSEN has been working on robotic inspection technology for over ten years. The tools that have been developed for pipeline inspection fall into two main categories: internal (inside the pipe) and external (outside the pipe) robotic inspection tools.
Internal Robotic Inspection
The first tool that can be considered as an internal robotic tool is the ROSEN speed control inspection tool. The speed control tool can make decisions about, and vary, the amount of gas bye-pass required to control the acceleration and speed of the unit as it travels and inspects in a gas pipeline. The tool and typical dynamic characteristics are shown in Figures 6 and 7.
In comparison with the speed control tool, other designs and constructions of ROSEN robotic inspection tools are much more complex. Increased sophistication is needed because these tools are designed to inspect difficult so-called ‘unpiggable’ pipelines. A wide variety of obstacles, distortions and diversions can be encountered in such pipelines. The inspection tools therefore need to possess significant ‘intelligence’, articulation and maneuverability. In addition they must be tolerant of different product types, properties and dynamics (chemistries, pressures, temperatures, speeds, accelerations, etc.). An example from the large range of ROSEN robotic designs under evaluation and testing is shown in Figure 8.
External Robotic Inspection
ROSEN operates external robotic tec hnology in the form of its Robotic Pipe Scanner (RPS). The tool is shown in Figure 9.
The RPS is a fully self -contained inspection unit which uses the MFL principle to measure metal loss defects in above-ground pipes. The full circumference of the pipeline is inspected at very high resolution in a single pass. Any obstacles on the pipe, such as flange connections, are easily bye-passed by expanding the tool as it passes over the obstacle. This is achieved by using hydraulically -operated articulated joints on the magnetic and mechanical systems of the tool.
Axial Flaw Inspection
Traditional MFL inspection technology has difficulties detecting narrow, longitudinally oriented defects (axial flaws) due to the adverse orientation of the magnetic field. Transverse Flux Technology can overcome this problem by inducing the magnetic field in the transverse direction, perpendicular to the longitudinal axis of the pipeline and the defect. To do this the pipe wall is magnetized circumferentially. A typical Axial Flaw Detection (AFD) Tool is shown in Figure 10.
Other Inspection Advances
In addition to the above technologies which are under consideration or being implemented by the client/ROSEN Workshop, a range of other technical advances are being planned or being applied now.
These include:
•
GPS geo-referencing solutions, e.g. ROSEN XYZ Mapping tool•
GIS System•
Risk Assessment, Fitness For Purpose and other integrity software applications•
Digitization of data and entry of data into Legacy Database•
Dual diameter MFL inspection tools•
Integrated MFL sensors and new electronic systems•
Contact-less electronic geometry measurement•
Bi- Directional MFL inspection technology•
Guided Wave Ultrasonic technologyOf special note are the advances which ROSEN has made in MFL sensor designs and inspection electronics.
Integrated Sensors – the internal and external defect discrimination sensors, previously carried as two separate sensor arrays, have been integrated into a single sensor block. With the new design there is only one sensor ring on a ROSEN corrosion detection tool, instead of the previous two rings. The single sensor housing is able to detect and measure corrosion defects and tell whether defects are external or internal (Figure 11). The new design is based on Hall elements for absolute (DC) field measurements, and allows faster and easier tool preparation and maintenance. The new sensor provides much greater reliability. It is fully digital so although there are numerous sensors within the housing there are only two output wires.
New Inspection Electronics – the new system uses high performance electronic circuits. ROSEN has introduced a new miniaturized data acquisition circuit card for use in alltypes of ILI tool. The new card is based on state of the art electronics and is able to tell for itself the type of sensor which is plugged into it (Plug and Play technology). The new system is even more reliable than previous systems and can be used on any ROSEN tool. All of the different kinds of ROSEN inspection technologies w ill now use only a single type of data acquisition system to make tool operations and tool maintenance much faster, easier and lower cost. A major benefit will be an even greater reduction in reruns through tool problems.
With the latest electronics technologies it is now possible to build revolutionary innovations into ROSEN inspection tools. One example of this is the use of the tow coupling to house the electronic data acquisition system. The new coupling is shown in Figure 12.
A data acquisition syste m built into a tool’s tow coupling achieves significant reductions in the tool’s weight and length. The tool can thereby operate in a wider range of pipelines without making expensive and time-consuming alterations to pig traps and pipework. This can provide a solution to some so-called unpiggable pipelines.
Integrated Solution
Having jointly studied key areas of the pipeline integrity control system, the pipeline operator and ROSEN are now finalizing planning for a pilot project aimed at demonstrating the benefits of a truly integrated approach to integrity management. It is proposed that personnel from relevant divisions of the client, together with ROSEN and third party experts, will work as a single team to optimize the integrity control on a single pipeline. As required, new inspection technologies, software, data analysis and other tools will be used in the project. New technical developments will be undertaken where necessary. If successful, this pilot project may become the blueprint for further projects in the full pipeline network.
Case Study 2 - Fitness For Purpose Assessment
Description: Offshore Pipeline, 10 km x 20” crude oil, 7 years old.
This case study deals with operations principally within the control components of Inspections, Investigations, Settings, Processor and Database. In performing the services, ROSEN was able to facilitate improved knowledge and understanding between the client, itself and key subcontractors by using major principles of the control approach as a basis for communications and operations.
In 2002 ROSEN performed a Fitness for Purpose (FFP) Assessment of a 20” diameter offshore crude oil pipeline. The basis for the FFP was a Magnetic Flux Leakage (MFL) in-line inspection (ILI) survey performed by ROSEN in 2001. The project was characterized by efficient teamwork between the client, ROSEN and key subcontractors. Prior to the project all parties had established efficient working relationships based on clear understandings and effective communications.
The scope of the pipeline FFP was:
•
Perform an engineering assessment on the 2001 inspection results in accordance with ASME B31G.•
Review and assess corrosion and weld features along the pipeline in accordance with ASME B31.8 and ASME B31G.•
Determine the FFP of the pipeline to the end of its design life based on operational and corrosion information.•
Assess the current corrosion management philosophy for the pipeline to confirm the effectiveness of corrosion monitoring and mitigation programs.Table 2 summarizes the key pipeline parameters used in the FFP Assessment.
2001 Inspection Survey Results
A total of 1031 internal metal loss features were located in the pipeline, with four metal loss corrosion anomalies being identified with ERF’s ≥ 1. Therefore, in terms of parent pipe corrosion, the pipeline was determined to be not fit-for-purpose. However, it was found that the material grade of API 5L X42, supplied to ROSEN in the Pipeline Inspection Survey Questionnaire, did not
match the pipeline materials test certificates provided later by the operator, which stated grade API 5L X52.
Due to the increased strength of the material, the FFP assessment found that the anomalies identified by the ROSEN ILI survey, that had an ERF ≥ 1, actually had an ERF < 1 at the time of the inspection. Therefore they complied with AMSE B31G and at the time of the survey the pipeline was considered to be fit-for-purpose.
The findings of the ROSEN inspection survey are summarized in Table 3.
ROSEN also identified 1 girth weld feature and 5 mill features. These were identified as construction anomalies which had successfully passed the initial system pressure/hydrostatic test. They were therefore judged to be compliant with B31G.
FFP Assessment
Metal loss anomalies caused by corrosion were as sessed in accordance with the methodology of ASME B31.8 (1999) [2], which references ASME B31G (1991) [3] for the assessment of corrosion anomalies in plate metal. An MAOP of 6.89 MPa was used for the FFP. To account for the possibility that the inspection data was under-sized, the FFP assessment was performed by applying the ILI sizing tolerance to individual anomalies.
Figure 13 summarizes the results of the FFP assessment. All anomalies were within the limit of acceptability of ASME B31.G and therefore complied with ASME B31.8 (1999).
Corrosion Management Philosophy
The pipeline was installed to transport a sweet multiphase product with a water cut of 0.5% by volume. While the main corrosion issue was the internal corrosion due to the water carried with the oil and gas, external corrosion was also addressed in the FFP.
External corrosion protection was achieved by the application of a coating, a 75- micron layer of Carbozinc 11 and 4 mm (min) layer of coal-tar enamel grade 105/8, and a sacrificial anode cathodic protection system. While the ILI Survey did not find any external anomalies, the absence of reported external anomalies was not taken as a reliable indicator that the CP or coating system were working effectively or that they would continue to work effectively in the future. Appropriate CP and visual surveys of the pipeline were recommended to assess this.
Internal anomalies were reported by the ILI survey around the internal circumference of the pipeline, with a prevalence of corrosion between the 2:00 and 10:00 positions. A high concentration of corrosion anomalies were located at the 3:00 and 9:00 o’clock positions, consistent with stratified / stratified-wavy flow of the product. In addition to the flow regime, the width of the band of anomalies could also be attributed to the water cut varying over time.
Lack of corrosion at the 6:00 o’clock position suggested that the inhibitor was relatively effective in the water phase. Some corrosion was evident in the 12:00 o’clock position. The corrosion morphology and location did not indicate significant flow or localized corrosion mechanisms and suggested that the corrosion was occurring at the crude/water interface. Typically, this is a function of the corrosion inhibitor performance, in particular the partitioning behavior of the inhibitor.
Measured Corrosion Rate
The coupon data from the corrosion rate monitoring of the pipeline (June 1995 – September 2000), showed significant variability with higher corrosion rates over the last twelve months of monitoring. The average corrosion rates for the two monitoring points were respectively 1.32 mm/year and 0.71 mm/year. These rates were significantly higher than the average rate of 0.49 mm/year as determined by the ILI data.
Internal chemical treatment of the pipeline consisted of injected corrosion and scale inhibitors, this being the only practical mitigation option due to the large volume of water in the pipeline. The overall effectiveness of the inhibitor in reducing the corrosion rate would be influenced by its availability (the time the inhibitor was made available to the system) and its efficiency (how efficient the inhibitor was in reducing corrosion). The observed corrosion monitoring data suggested that the inhibition system was not performing at 100% availability but no information was available on corrosion-upset conditions (loss of inhibition, incorrect rates etc.).
There had been changes of corrosion inhibitors over the life of the pipeline and on each change there had been a several- month period where the amount of injected corrosion inhibitor was increased to a steady level. Studies showed there was no direct correlation between the start up of the change of inhibitor and the coupon data supplied by the operator. The coupon data exhibited significant variability which is shown in Figure 14.
Pipeline cleanliness is an important factor with regard to internal corrosion mechanisms. Regular cleaning of a pipeline helps to mitigate corrosion by removing corrosion products and solids and improving the distribution of inhibitor. The pigging records for the pipeline showed it to be clean and free of solids, however no regular maintenance pigging program was evident from documentation supplied by the operator.
Line Pipe Materials
Carbon steel line pipe (API 5L X52 ERW and Seamless) and weld filler material (AWS A5.5 E8010- G), with the addition of 0.5 –1.0% chromium (Cr), were used in the construction of the pipeline. The chromium had been added to the carbon steel for improved corrosion resistance and comments were sought by the operator with regard to the chromium addition and its effect on corrosion resistance.
A working party report [4], produced by the European Federation of Corrosion on CO2 corrosion control in oil and gas production, discusses the control of wet CO2 corrosion by micro alloying, in particular the effect of chromium. It states that independent work done by Sumitomo and Kawasaki shows a beneficial effect in CO2 saturated water below 90°C. The report suggests that carbon steel with 0.5% Cr added seems to offer an acceptable balance between corrosion resistance and loss of toughness. The report does not, however, quantify the benefits of the chromium additions.
According to the line pipe material test certificates supplied by the operator, the ERW pipe had a specified Cr content of 0.45 - 0.65 % Cr and the seamless pipe heat analyses indicated a Cr content of 1.08 - 1.10 %. It is generally accepted that significant improvements in the corrosion resistance of carbon steels is achieved with additions of chromium above 12% and more usually, in the case of 316 stainless steel, 17% chromium. It is considered that if small additions of chromium do improve the corrosion resistance of the steel, then it would only be marginal. Additions of 3 or 5% Cr would be considered detrimental to the toughness of carbon steel.
In order to quantify the impact on corrosion resistance of the addition of 0.5 – 1.0% Cr, it would be incumbent on the supplier of the pipe material to provide quantitative evidence (laboratory and field) for the case study environment. This was advised to the operator.
Since the ILI survey did not indicate any corrosion related girth weld anomalies it was assumed that the weld filler material chosen was adequate from a corrosion poi nt of view. The weld electrode specification (AWS A5.5 E8010- G) indicated a chrome content of approximately 0.5%. However, the final weld composition could have potentially varied from this if volatiles were lost during welding. The composition may also have been influenced by the degree of dilution with the base metal. The final weld composition could be found through analysis.
Corrosion Mitigation
The principal means of internal corrosion mitigation was by chemical injection. The correct selection of che mical, coupled with injection at adequate rates and commensurate with ongoing changes in production, should have been capable of reducing the inhibited, or residual corrosion rate to <0.05 mm/yr. This would require field and laboratory assessment of the corrosion inhibitor under conditions at least as onerous as those expected during normal operation. Achieving these levels of inhibitor effectiveness often requires larger volumes of inhibitor, which in turn often requires modification to the chemical injection hardware required for application.
The pipeline operator was recommended to review the inhibitor availability, to ensure adequate design and operation of the system. Industry standard operating practices can achieve inhibitor availability of 95% (18 days per year without effective
inhibition) although through implementation of the recommendations for industry best practice, it is possible to achieve inhibitor availability of 99% or greater.
Corrosion Monitoring
The pipeline operator was provided with guidance for future corrosion monitoring to provide feedback on the performance of the corrosion mitigation program. To achieve high levels of availability of the inhibitor, a corrosion monitoring system needs to be capable of providing real time feedback on the changing corrosivity of the produced fluids. Depending on the level of performance required, the corrosion monitoring devices would need to meet the sensitivity demands of the corrosion mitigation system.
Corrosion Rate Assessment
As the pipeline design life was 25 years, there were still approximately 18.5 years to end of design life from the date of the 2001 ILI run. The corrosion rate assessment [5, 6] analyzed the continuing FFP of the pipeline through a range of derived corrosion scenarios.
Th e assessment was conducted to ASME B31G. It examined the growth of the reported anomalies based on the predicted / observed corrosion rates. From these results a high level repair schedule and recommended time intervals to the next ILI inspection were developed.
The corrosion rates used for the corroded case assessments are given in Table 4. The coupon data was not used as a corrosion rate criterion due to the variability of the data produced by this method.
The anomaly growth analysis used the MAOP (6.89 MPa) as the limiting design operating pressure. From production reports the typical operating pressure for the pipeline was 1.23 MPa and, if this operating pressure was continued until the end of pipeline life, de-rating the pipeline could provide another option to minimize the number of repairs and frequency of ILI surveys.
The data generated from the corrosion rate assessment was used to generate high-level repair and ILI re- inspection schedules.
Operational Options
The continued FFP of the pipeline would be governed by maintaining the pipeline within code-based on the analyses performed there were three main options to continue operating the pipeline, these being:
1. Do nothing and re-assess, using an ILI survey, the state of the pipeline near to the point it becomes out of code to determine if the corrosion management plan had improved the remaining life of the pipeline.
2. Maintain the current pipeline MAOP and repair as per the high-level repair schedule.
3. De-rate the pipeline re-determining the pipeline’s FFP and high- level repair schedule based on the new MAOP.
The chosen option would be based on operational, technical and economic considerations and would be considered along with a revised corrosion management plan and the ability to maintain the corrosion of the pipeline as low as reasonably possible.
High Level Repair Schedule
In leading five-year blocks, the high-level repair schedule reported the anomalies that were calculated to become defects and require repair to remain within code. It was assumed the defects identified would be repaired at the beginning of a block year and defects would be prioritized by refining the repair schedule.
Based on the condition of the pipeline at the time of the ROSEN 2001 ILI Survey the first instance at which an anomaly would become a defect for each practical/observed corrosion rate is shown in Table 5.
A summary of the high- level repair schedule is shown in Table 6.
To minimize the number of repairs that would be required, the corrosion rate of the pipeline must be reduced. Therefore, the existing corrosion management philosophy / practice should be optimized to reduce the number of future repairs. If the existing corrosion rates were sustained, then repairs or de-rating of the pipeline could be required within 2 years of the date of the ROSEN 2001 ILI Survey. This period of time could be increased to 5 years if the corrosion rates were reduced to a best-case corrosion rate (0.295 mm/year). Optimizing the use of inhibitors and cleaning regimes would assist in controlling the internal corrosion of the pipeline.
80% Loss of Wall Thickness Limit
The ILI anomalies were analyzed to determine in which year they could potentially reach the 80% loss of wall thickness limit imposed by the code. This analysis ignore d the effects of the MAOP. The anomalies were grown based on the corrosion rates defined for the high-level repair schedule.
Table 7 lists the year at which the 80% wall thickness criteria would be exceeded for the 7 deepest anomalies.
ILI Plan
The criterion for the next ILI run was based on 80% of the time to the next failure. The results of this analysis are shown in Table 8. It was recommended that the medium case corrosion rate should be used to set the next ILI run.
In summary, the FFP assessment performed by ROSEN produced the following main results:
•
Based on the fitness-for-purpose of the pipeline from an internal corrosion perspective, current corrosion management philosophy and practices could be optimized.•
If the current predicted worst-case corrosion rate (0.66 mm/year), as determined from the ROSEN inspection data, was sustained then repair or de-rating of the pipeline could be required within 12 months.•
The time to repair or de-rating of the pipeline could increase to 4 years if the corrosion rate, as determined by empirical corrosion modeling, was reduced to optimal levels (0.295 mm/year).•
The continued operating life of the pipeline would be significantly affected by the corrosion rate, influencing the number of defects presenting over time and therefore the cost of repairs.•
Optimizing the use of inhibitors and cleaning regimes would assist in controlling the internal corrosion of the pipeline.CONCLUSIONS AND RECOMMENDATIONS
This paper has presented some of the experiences of a service company in the field of pipeline integrity management. While the subject can appear confusing, there are means by which a systematic approach can be taken to improve all-round communications, understanding, and technical effectiveness.
These means inc lude:
•
Understanding the relationships between management, information and analytical systems•
Adopting a standard high level model for integrity control•
Obtaining a better appreciation of how knowledge sharing operates in relation to trust•
Understanding the importance in integrity solutions of closer working integration of people from the client and service companiesIn particular we recommend that an integrity control review process should be considered that uses commonly understood principles. For example,
•
Start with a good high- level model of pipeline integrity management. The control loop model is based on well established engineering principles.•
Summarize existing situations in each major component of the model.•
Detail the Settings – state clearly what is required.•
Detail the Processor – state clearly what is already known about the pipeline.•
Determine the differences between what is required and what is known.•
Determine the action plan needed to eliminate the differences.•
Knowledge-share at each step, internally and externally, with relevant people and companies.The effectiveness of the integrity management process can be improved by a number of simple steps.
•
Standardize from the top down. Start with a clear M- I-S statement and be clear about the manage ment (M) needs.•
Implement means to improve knowledge-sharing.•
Systematically build trust - knowledge-share at all stages.•
Be ‘scientific’ – be wary of commercial gimmicks and buzz words.The case studies in this paper have demonstrated that technology can be successfully applied to pipeline integrity solutions, but the greatest benefits are obtained when all parties involved work together beyond the expectations of a normal company/subcontractor relationship.
Based on ROSEN’s experience of integrity manag ement, we recommend that greater considerations should be given to the above points. Through an even better mutual understanding of client needs and potential technical solutions of the service company, we believe that exciting new technologies can be developed. These new solutions would be better focused on real needs if the needs could be appreciated in the light of the complete system of integrity control.
REFERENCES
1. “Trust and knowledge sharing: A critical combination”, Daniel Z. Levin, Rob Cross, Lisa C. Abrams and Eric L. Lesser, IBM Institute for Knowledge-Based Organizations (2002)
2. ASME B31.8 (1999), “Gas Transmission and Distribution Piping Systems “.
3. ASME B31G (1991), ”Manual for Determining the Remaining Strength of Corroded Pipelines”.
4. European Federation of corrosion Publications – Number 23, Edited by M. B. Kermani and L. M. Smith, “A Working Party Report on CO2 Corrosion Control in Oil and Gas Production – Design Considerations”.
5. NORSOK Standard (1998), M-506 CO2 corrosion rate model.
6. NACE (2001), Ian Rippon, “Life Cycle Cost for Carbon Steel”.
ACKNOWLEDGEMENTS
ROSEN wishes to acknowledge the very significant contributions made by its clients, associates and subcontractors in the preparation of this paper.
Figure 1. The MIS Management Process Triangle
Figure 2. Pipeline Integrity Control System
Legacy
Database
M
Management
I
Information
S
System
Flow of
Development
Process
Iterative
Feedback
Figure 3. ROSEN EMAT Inspection Tool
Figure 4. EMAT Scan of Axial Cracking
Figure 6. ROSEN Speed Control Inspection Tool
Figure 7. Typical Dynamic Characteristic of Gas Volume/Time for the Speed Control Tool
Figure 8. ROSEN Robotic Inspection Tool Traversing Bends
Figure 10. Axial Flaw Detection (AFD) Tool
Figure 11. ROSEN Integrated MFL Sensor
Figure 13. Results of FFP Assessment based on B31G and Pipe Grade API 5L X52.
Control Loop Components Case Study Description Settings Inspections (Pipe Wall) Investigations (Environment) Data Storage Processor Feedback Actor Feedforward Actor Comments 1 Onshore & Offshore Pipeline Network: >20,000 km pipelines, gas & liquids, ages from new to many decades old
•
Value driven•
Zero leak policy•
Repair pipe to as-constructed specifications•
Hierarchal Management•
8 divisions involved in IM decisions•
Int. regulations•
B31G•
All lines require >20y remaining life•
Proactive IM required•
Need to build more new lines•
ROSEN MFL ILI: > 10,000 km total; >3,000 km p.a.•
Geometry surveys Defects:•
External defects•
Internal defects•
Mid-wall defects•
CIPS•
Terrain Surveys•
Third Party Monitoring•
Mixed digital and paper records•
Some GPS•
Non-integrated•
Involves IT Depart-ment•
Involves IT Department•
Range of software applications•
Many models Main Ongoing Processes:•
Routine maintenance•
Rehabilitation•
Life extension•
Defect Challenges (e.g. cracks, laminations)•
Large numbers of Metal Loss Repairs•
Linepipe replace-ments•
Ongoing CP improvem-ents•
Ongoing coating repairs•
Ongoing route improveme-nts•
Pig cleaning Client required support for optimization of its existing integrity management system and to advance from reactive to proactive mode 2 Offshore Pipeline: 10 km x 20” crude oil pipeline; 7 years old•
Value driven•
Engineering Management•
3 divisions involved in IM decisions•
Int. & Gov’t regulations•
B31G•
Line requires >18y remaining life•
Proactive IM required•
ROSEN MFL ILI•
Geometry surveys Defects:•
Internal defects•
ROV•
Diver insp’s•
Mixed digital and paper records•
GPS•
Non-integrated•
Involves IT Depart-ment•
Involves IT Department•
Limited software applications•
Limited models Main Ongoing Processes:•
Routine maintenance•
None•
Anode maintenance•
Pipe stabilization•
Inhibitor applications•
Pig cleaning Client required ROSEN to:•
Perform an FFP•
Assess corrosion and weld features•
Assess corrosion management philosophyDESCRIPTION / PARAMETER VALUE
Nominal Diameter 20 inch
Pipe type ERW / Seamless
Material Grade (Actual) API 5L X-52
Nominal Wall thickness 12.7 mm
MAOP 6.89 MPa
Design pressure 8.27 MPa
Min operating pressure 150 PSI (1.03 MPa)
Max operating pressure 200 PSI (1.38 MPa)
Normal operating pres sure 150 PSI (1.03 MPa)
Min operating temperature 160 °F (71 °C)
Max operating temperature 200 °F (93 °C)
Normal operating temperature 160 °F (71 °C)
SMYS 358 MPa
UTS 455 MPa
Product Crude Oil (3 Phase)
Installation Year 1995
Remaining life (Design Life 25 years) 18 years
Table 2. Pipeline Data used in the FFP Assessment (10km, 20 “ Crude Oil Pipeline)
FEATURE DESCRIPTION (Type / Cause) NUMBER OF FEATURES
40-59% Wall Loss – Internal at pipe wall 3
20-39% Wall Loss – Internal at pipe wall 1028 10-19% Wall Loss – Internal at pipe wall Not Identified Total Number of Wall Loss Features 1031
Non- Metal Loss Features - Weld Features 1
Non- Metal Loss Features - Mill Features 5
Total Number of Non-Metal Loss Features 6 Other Non- Corrosion Features (sleeves, flanges, etc) 22
Total Number of Features 1059
Table 3. 2001 ILI Survey Results
Case Corrosion Rate (mm/year)
Corrosion Rate Criteria
1 0.295 Based on a modeled corrosion rate [4] of 4 mm/year and an inhibitor availability of 95%. At 100% availability the residual corrosion rate [5] is 0.1 mm/year.
2 0.49 Based on the average corrosion rate. Determined from the ROSEN 2001 ILI Survey metal loss data.
3 0.66 Based on the average corrosion rate plus 2 standard deviations (2σ), thus giving a 95% confidence level that the reported defects will be equal to or less than the stated corrosion rate. Determined from the ROSEN 2001 ILI Survey metal loss data.
Table 4. FFP Corrosion Rate Criteria
Corrosion Rate Time to Failure (1)
Worst Case (0.66 mm/year) 2 years
Medium Case (0.49 mm/year) 3 years
Best Case (0.295 mm/year) 5 years
Table 5. Time to the First Anomaly Becoming a Defect
Repair Block (1) Corrosion Rate Failed Anomalies Best Case (0.295 mm/year) 0 reported anomalies fail Year 0 Medium Case (0.49 mm/year) 3 reported anomalies fail Worst Case (0.66 mm/year) 6 reported anomalies fail Best Case (0.295 mm/year) 4 reported anomalies fail Year 5 Medium Case (0.49 mm/year) 13 reported anomalies fail
Worst Case (0.66 mm/year) 50% of reported anomalies fail Best Case (0.295 mm/year) 9 reported anomalies fail Year 10 Medium Case (0.49 mm/year) 100% of reported anomalies fail
Worst Case (0.66 mm/year) 100% of reported anomalies fail Best Case (0.295 mm/year) 25% of reported anomalies fail Year 15 Medium Case (0.49 mm/year) 100% of reported anomalies fail
Worst Case (0.66 mm/year) 100% of reported anomalies fail
(1) The anomalies that were expected to be out of code during a five-year period and therefore requiring repair. The number of reported failed anomalies accumulates from period to period.
Table 6. Summary of Repair Schedule
YEAR (1) AT WHICH 80% WALL THICKNESS CRITERIA IS EXCEEDED FOR EACH CORROSION RATE
7 DEEPEST ANOMALIES
- DEPTH (%) 0.295 (mm/yr) 0.49 (mm/yr) 0.66 (mm/yr)
45 16 10 7-8 42 17 11 8 41 17-18 11-12 8-9 39 18-19 11-12 8-9 38 19 11-12 9-10 37 19-20 12-13 9-10 36 19-20 12-13 9-10
(1) Commencing from the date of the ILI run (July 2001)
Table 7. Year at which 80% Wall Thickness Criteria is Exceeded
CORROSION RATE NEXT RUN
Worst Case (0.66 mm/year) January 2003
Medium Case (0.49 mm/year) November 2003
Best Case (0.295 mm/year) July 2005
