PIPELINE ENGINEERING PDF
is usually ignored, as the equation applies to a section of pipe). The above equation is an alternative way of writing the mechanical energy balance. It is not a. A Quick Guide to Pipeline EngineeringWPNL A Quick Guide toPipeline Engineering D. Alkazraji BEng, CEng, MIMec. Piping and. Pipeline. Engineering. Design, Construction,. Maintenance, lntegrity, and Repair. George A. Antaki. Aiken, South Carolina, U.S.A.. ~. Taylor &.
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PE Oil & Gas Pipeline Design, Maintenance & Repair. Dr. Abdel-Alim Hashem. Professor of Petroleum Engineering. Mining, Petroleum & Metallurgical Eng. Pipeline engineering, ferritic-pearlitic and bainitic steels (pipeline-steels), duplex- steels, pipeline failures, natural gas pipelines, crack-arrestors, pipeline. pipelines are in the news. The SMCC has prepared this backgrounder on crude oil and pipeline engineering. If you would like to speak to an expert about this.
They have limited application to higher-grade steels, i. Accurate information is needed for any corrosion assessment. The following should be determined: Once this information is available, an accurate assessment of corrosion features can be conducted. G code  occurred in the late s and was based on experimental data from full-size tested pipe sections, using corroded pipe sections and pressurizing them to failure.
This enabled a better understanding of defect behaviour, allowing semi-empirical mathematical expressions to be developed and validated against experimental data. The expressions assumed that the failure of blunt corrosion defects is controlled by the yield stress of the pipe material.
Efficient strength and fatigue analysis of subsea pipelines
The term effective area is based on the amount of metal loss on the pipe and assumes that strength loss due to corrosion is proportional to the axial length of the corrosion along the pipe. The basic expression for effective area is as follows: WPNL 77 A Quick Guide to Pipeline Engineering Since steel has a certain amount of plasticity, the material deforms in a way that creates a bulge as the corrosion feature begins to fail.
This folias factor M is commonly known as the bulging factor. G assessment method When applying the effective area method using B G, the primary assumptions are as follows: The corroded area is approximated as a parabolic shape. As can be seen, B G was one of the early developed assessment methods and is still one of the most widely used by pipeline operators. G also provides an alternative approach for which a maximum acceptable length for a corroded area can be calculated. This is done using the following equation: This new method was validated against numerous burst tests on actual corrosion pipe defects.
Differences between this new method and the previous one were as follows: A more accurate three-term expression for the folias factor is provided.
G because: It includes a more accurate three-term expression for the folias factor or bulging factor. This method is more suitable for long areas of general corrosion. The citation to this reference reference  conveys no rights to the reader in the material referenced and it may not be used without the prior written permission of Pipeline Research Council International, Inc. Both BG Technology and DNV generated an extensive database of burst tests on pipe specimens, incorporating single corrosion defects, interacting defects and complex corrosion shapes.
This then enabled criteria to predict the remaining strength of corrosion defects to be developed. DNV-RP-F is divided into two main assessment approaches for assessing single, interacting and complexshaped corrosion. Corrosion failure pressure is then multiplied by a safety factor to obtain the safe working pressure, and hence uncertainties in sizing are left to the user to take into account. This is introduced so that there is a safety margin between the operating pressure and failure pressure of the corrosion defect this is normally taken to equal the design factor of the pipeline.
There are therefore two stages in the assessment approach: Calculate the failure pressure of the corrosion defect: Then calculate the safe operating pressure using the total usage factor: G , then this is considered unacceptable. In summary, the main differences between this assessment approach and B Failure is controlled by the UTS the ultimate tensile strength of the material.
It utilizes a different folias factor: G, these criteria were developed and are also known as the Shell 92 criteria . As shown in the above equation for calculating the failure stress, this uses the same effective are equation. The citation to this reference reference  conveys no rights to the reader in the material referenced and it may not be used without the prior written permission of Pipeline Research Council International, Inc.
These failure mechanisms were as follows: Defects in moderate- to high-toughness pipe fail by plastic collapse and the UTS controls this failure. Defects in low-toughness pipe such as in older pipeline steels fail in a toughness-dependent mode.
As a result of this research, new residual strength criteria were developed for defects in moderate- to high-toughness pipe. These criteria are only applicable to pipe operating above the brittle—ductile transition temperature i.
Often when data are received from an ultrasonic or magnetic inspection tool, there will be hundreds or even thousands of reported internal and external corrosion features, particularly in some of the older pipelines. Assessment curves are therefore an effective method to show whether these features are acceptable at the current maximum allowable operating pressure MAOP of the pipeline.
Using assessment codes, the operator can calculate failure depths for different lengths of corrosion at the current MAOP. It is important for any engineer when conducting calculations to take into account uncertainties and operational considerations. These may include: Employing the safety factors in Table 6. For example, applying this to Fig. It is possible to apply this procedure for any of the codes shown in Table 6.
In developing a corrosion management strategy it is essential to determine if corrosion growth is occurring along the pipeline route. This can only be achieved through repeat inspections or the use of corrosion coupons placed alongside the pipe. Assuming no other secondary loads, calculate the stress components acting on the pipeline: Results show that the majority of the reported corrosion features are external.
In addition, ultrasonic measurements show that the minimum wall thickness is 8. G The following example shows two areas of deep corrosion in a gas pipeline, detected by a magnetic inspection run and subsequently excavated for detailed measurement.
The pipeline is made from Xgrade MPa Are these corrosion features acceptable to B G based on their axial dimensions see Fig. Check that all required data are to hand: Always remember to keep units consistent.
Step 2. This shows that neither failure depth is acceptable at a safety margin of 1. Consequently, the operator would have two choices: It is important to note that this assessment assumes that the corrosion defects are not growing. In some instances where WPNL 94 Pipeline Maintenance the corrosion defect is growing, the coating should be replaced at the site of the corrosion, and the cathodic protection levels should be checked to ensure that the pipe is fully protected.
Possible sources of axial load include: In most cases the dominant stress on the pipe is the hoop stress, but consideration must be given to the circumferential extent of corrosion. A method of assessment was proposed by Kastner  for a part-through wall defect subject to an axial load see Fig. The dynamic assessment approach utilizes the S—N approach to determine the remaining fatigue life of a dent using its peak depth.
These have similar shape characteristics to a buckle. These result in lower failure pressures caused by: Typically, these dents are held in place by a rock the indentor and are subjected to fatigue loading. They are generally found at the bottom of the pipe, caused by construction during positioning of the pipe in the trench.
Important characteristics of these dents are that: According to inspection data, they are usually found at the top of the pipe. As the indentor is removed, owing to the internal pressure, elastic springback occurs which reduces the depth of the dent. The following list shows some of the codes that can be used to provide guidance on acceptable dent depth: It must be noted that the guidance given by most codes only covers plain dents.
For dents associated with other features such as gouges, cracks or corrosion, most codes do not allow these combinations, and consequently there is little recommended guidance. Dents associated with welds can result in low burst pressures, and are susceptible to cracking at the weld toe.
Industry operators have conducted a number of tests on dents associated with welds and reported some specimens exhibiting very low failure stresses . Some pipeline operators follow this guidance, but ultimately the dent must be checked for the presence of cracks using non-destructive testing.
Dents located at the top of the pipe are frequently caused by third party damage and may contain other defects. In addition, these are likely to be unconstrained, so they should be assessed for fatigue.
Under fatigue loading conditions, the depth of the dent may change see Fig. The important parameters when assessing dents are as follows: Because of re-rounding effects, the depth of a dent created at zero internal pressure will be different under pressure loading conditions.
Dent depth changes under different internal pressure conditions i. This effect is known as re-rounding, which changes under different fatigue loading conditions. If fatigue loading is high enough, the dent will ultimately fail. A common method for estimating the fatigue life of steels is through the basic S—N curve, displaying stress range versus number of cycles. This basic approach has been utilized within the pipeline industry, applying the basic S—N curve and relating this to the increased stress concentration due to the dent.
A number of models have been developed using a semiempirical method for predicting the fatigue life of plain dents. These are based on the use of an expression for stress concentration due to the dent.
The fatigue life is then calculated using the basic S—N curve. There has been Figure 6.
On-Site Piping and Pipeline Troubleshooting, Consultation and Maintenance Services
These methods are based on a basic design S—N curve for plain pipe material, with fatigue life being calculated by taking into account the stress concentration due to the dent. Basic fatigue design S—N curves include: PD ;. DIN .
The fatigue life of a plain dent is then calculated using the following expression: Currently, the best technologies for detecting dents are highresolution geometric tools that give an accurate estimate of peak depth. Unfortunately, these tools alone do not provide all the required information for an accurate dent assessment. Wall thickness, orientation and relative distance from a weld are also important parameters.
Hence, a geometric inspection tool usually follows intelligent tools such as: Consider the following example of a static dent assessment. A natural gas pipeline was inspected using ultrasonic and geometric inspection tools, and showed the dent illustrated in Fig. Using the guidance provided on static dent assessments for pipelines, what recommendations would you make?
Is the dent plain? Yes, this is not associated with a seam weld, and is therefore a smooth plain dent. As discussed earlier, dents associated with welds can have low burst pressures and are generally recommended for repair. What is the peak depth of the reported dent? Most codes would not allow a dent of this size and would recommend a repair.
In addition, this dent is located in the top half of the pipeline, so two conclusions can be made: The dent may be unrestrained. The dent may also have been caused by third party damage.
Since B However, a further check on this dent would be to calculate the remaining fatigue life. Step 3. Hence if the pipeline had numerous reported dents, then as previously discussed, dents at the top and bottom of the pipeline can be separated for assessment.
In summary, API  suggests that: Dents at the top of the pipe are likely to be unrestrained and subjected to fatigue loads. Dents at the bottom of the pipe are likely to be constrained i. In conclusion, based on a static assessment using most codes, this type of dent would be unacceptable. The main types of construction defect include: As this shows, there are numerous types of defect to consider, but some of the more serious types of defect are laminations and cracks i.
Lamination features can bulge when operating in sour conditions and also start to form hydrogen-induced cracking see Section 5. In addition, planar-type defects such as cracks can grow under fatigue conditions.
Code methods are used to assess planar defects. Most of the new pipeline steels, however, are now made with higher-toughness steels and are able to withstand higher critical defect sizes. Areas susceptible to cracks are the seam weld or girth weld, particularly in lowtoughness weld material. Currently, the best ways to detect cracks in a pipeline are by intelligent inspection using ultrasonic or special crack detection tools, or alternatively excavation and non-destructive testing using ultrasonics or magnetic particle inspection.
At present, the main codes used for assessing cracks are: BS ;.
API . Within BS  and API  the FAD is used as a method of taking into account the applied stress, geometry and fracture toughness of the pipeline. This type of diagram is used in levels 1 to 3 of BS to determine the acceptability of cracks by plotting a point on the diagram see Fig. A crack-type defect is considered acceptable or unacceptable depending upon whether this lies within an acceptable boundary. The assessment level used depends on the input data Figure 6.
The levels can be summarized as follows: Level 2 is the normal assessment route. Level 3 is based on complex ductile tearing resistance analysis. When the material approaches higher toughness values, it is predicted that a defect will fail by plastic collapse. However, when the material approaches lower toughness values, it is predicted that a defect will fail by brittle fracture. In addition to material properties, it is important to have accurate defect dimensions.
In order to determine a point on this diagram, values for load ratio and fracture ratio must be calculated. Only in levels 2 and 3 is stress—strain data required for the actual material curve. When determining a point on the failure assessment diagram, values for both Kr and Lr , the fracture and load ratio respectively, are required.
These are calculated using the following equations: This equation is based on the ratio of the stress intensity factor to the material fracture toughness, and is calculated using the following equation see BS : If there are no direct measurements of fracture toughness, the approach described in BS  details calculation of a toughness value based on the Charpy Vnotch energy. This provides a conservative lower-bound correlation applicable to a wide range of steels: How is the load ratio Lr calculated?
Level 2A utilizes a generalized FAD not requiring actual stress—strain data. For this approach, the FAD is represented by an equation of the curve, as shown in Fig.
If the point lies within the area of the line, the defect is considered acceptable. If it lies beyond the line, the defect is considered unacceptable. The main difference with this approach lies in the calculation of Kr and Lr. A brief description of each level is as follows. WPNL Pipeline Maintenance The level 1 assessment is used for assessing cracks that are away from other structural discontinuities, and is based on a simple screening assessment.
It should be used if the only loading on the pipe is due to internal pressure and there are no bending loads. The axes of this diagram show crack length, 2c, against material toughness represented by a reference temperature and the operating temperature. The API level 2 assessment is very similar to the level 2 Figure 6. Furthermore, detailed material properties are required and a determination of the current stress state such as by numerical analysis, or using code equations.
Consequently, API levels 2 and 3 assessments only apply if there are additional loading conditions other than the membrane stress , such as bending loads. Lamination features should have been detected during the pipe manufacturing process, but can often still be found following a pipeline inspection see Fig. Is the pipeline operating in sour conditions? Are the laminations sloping or parallel to the pipe surface? Are the laminations mid-wall or surface breaking?
Are they associated with any other feature such as a girth weld? Any lamination with a minor dimension exceeding 19 mm and an area greater than mm2 is deemed unacceptable. Methods are available to assess these features, such as API . The assessment method within API is again divided into different levels of assessment: Levels 1 and 2 apply if the laminations are parallel to the surface and have no through-thickness cracking.
A level 2 approach is required if the lamination is operating in a hydrogen environment i. A level 3 approach is required if the lamination is both WPNL A Quick Guide to Pipeline Engineering located at a structural discontinuity such as a weld and is also operating in a hydrogen environment. The pipeline is not operating in a hydrogen environment. If these conditions are not met, then a level 2 approach is required.
Check for the presence of cracks. If the distance between the lamination and the nearest weld is A level 3 analysis is only required if a reported lamination is oriented in the through-thickness direction or where cracks are reported to have developed at the weld. This involves conducting a detailed stress analysis using numerical analysis, or fracture mechanics methods.
pipeline design calculations.pdf
Reproduced courtesy of the American Petroleum Institute and may not be used without prior written permission. However, as previously discussed, other types of manufacturing defect include wall thickness variations and inclusions. With wall thickness variation, the operator must consider whether these variations are acceptable see Fig.
They can cause cracking if atomic hydrogen diffuses into these areas when operating in sour operating conditions, e. When operating in these conditions, a pipeline should be monitored through repeat inspections see Fig.
These variations can cause defects to fail at stress levels lower than the yield strength for a static load and are caused by: When conducting fatigue calculations, there are two main approaches: When a pipeline is subjected to fatigue loading, defects that should be considered for a fatigue assessment include: First, the S—N approach. If steel specimens are fatigue loaded at a number of different stress levels until failure occurs, and a plot of applied stress to logarithm number of cycles for failure is produced, this results in what is known as the S—N curve.
A characteristic of these curves is that there is a limiting stress level below which fatigue failure will not occur. Scatter is often present in these data owing to uncertainties such as material properties, loading conditions, test preparation, etc.
This S—N approach is generally used at the design stage for pressure vessels and is described in codes such as PD . To conduct a defect assessment on features i. Cracks formed by fatigue usually initiate at points of increased stress concentration such as welds, dents, manufacturing features or other forms of damage.
Experimentally it is possible to measure crack length during cyclic stress and plot this as crack length, a, versus number of cycles, N see Fig. The message of Fig. Consequently, the remaining fatigue life of a crack can be calculated using fracture mechanics. These terms are included in what is known as the Paris law equation . Another type of defect that also has the possibility of producing cracks are gouge-type defects.
These can seriously affect the burst strength of a pipeline and are often caused by mechanical damage or third party damage. It is, however, treated differently to corrosion as, by its nature, a gouge Figure 6. From inspection data alone, it is not usually possible to see whether a gouge has cracking associated with it.
Gouges should therefore be treated with caution and should be excavated and examined to check for the presence of cracks.
This can often be done through non-destructive methods such as magnetic particle inspection. There is various guidance in oil and gas codes on what to do with gouges, but it can be very general and will not always tell you whether they are acceptable in terms of immediate and future pipeline integrity.
Solutions to gouges that are used throughout the pipeline industry include: Finally, in order to conduct a detailed assessment of defects using the various approaches, it is important to have accurate pressure data, and to understand the maximum and minimum pressure variations. Pipelines are often subjected to fatigue loads, so analysis and interpretation of cyclic pressure data is essential. As can be seen, this is quite complex and can be confusing.
A method of simplifying this is to convert it into blocks of constant amplitude. This can be achieved by using cycle counting methods that simplify the pressure spectrum data. There are two basic rules that need to be followed see Fig.
Note that each path is equivalent to one half-cycle i. There are seven half-cycles which are determined as follows: Path E—F starts at trough E but encounters a trough more negative than its starting point, so it stops at F. Path G—H starts at peak G and stops at H when it encounters rain falling vertically. The maximum stress range is therefore chosen, since this would obviously be the most conservative approach. This is done using the following expression: The primary objectives are to: Figure 7.
Inspection of offshore pipelines is more complicated. In this case the following methods are often used: As shown, a signal loop is created, as both operators are electrically connected through the following items: The basic method of operation is that an alternating current a. This a. At the area of open coating defects the signal increases, detected as each operator passes over the defect. Limitations of this approach are that: It cannot detect disbonded coating i. It does not indicate whether the CP levels are adequate.
It cannot be used accurately to size a coating defect. It is usually employed on short sections of pipeline. The technique is able to detect coating defects, but it is primarily used to measure the effectiveness of the cathodic protection CP system. It measures two important parameters: What is the difference between these measurements?
As discussed in Section 3. It is important to measure the potential at the surface of the pipe i. The test post is also electrically connected to the pipe. As the operator travels along the pipeline route, measurements are taken above the pipe level, using an electrode that the operator holds. This method differs, however, in that it provides accurate results for sizing of coating defects. It works by using an aboveground operator to measure changes in voltage along the pipe i.
Hence, the severity of coating defects is categorized on the basis of the internal resistance drop: CP levels are inadequate. Both CP levels are low and coating defects exist, i. Currently there are numerous types of repair used throughout the pipeline industry, but they can be broadly categorized into two main types: A summary of the different repair methods is as follows: This repair method is often used to smooth out areas of increased stress concentration.
As discussed in Section 6. It is generally used as a last resort since it causes the most disruption and cost for the pipeline operator as the pipeline must be depressurized, decommissioned and the product appropriately disposed of. This can be very expensive and time consuming. It is generally used as a temporary repair for leaking defects, and is usually replaced within a year following application.
The epoxy is injected into the repair under pressure, which forces the mixture completely to encase the inside of the shell. Once the epoxy mixture has cooled, it forms an extremely high-stiffness material that prevents any further deformation of the pipe. Preparation of the repair and damaged region is as follows: The surface of the pipeline and each shell half are shot blasted to ensure a clean surface.
This has two purposes: The two halves of the repair are placed around the circumference of the pipe ready for setting the annular gap. This gap is adjusted to ensure that the shells are seated evenly around the pipe and that no bending stresses occur as a result of misalignment. The two halves are welded together and checked for any defects.
This is the most important part of the process, since a defective weld could fail during operation. A putty mixture is applied to the ends of the shell. This hardens and creates a seal at the ends of the repair.
When working in the pipeline industry, there are numerous pipeline codes and standards, calculation approaches and reference material that the operator must understand in order to make accurate and informed decisions. The book is divided into a number of sections including design, construction, risk assessment, pressure testing, operation and maintenance, condition monitoring, decommissioning and pipeline industry developments.
Throughout this book, alongside these basic principles, there is reference to the main standards and literature that are used in the pipeline industry. These references are essential for further information. The book provides engineers and students with up-to-date and accurate information on current best practice and the underlying principles of pipeline engineering.
For example, the engineer might need to know what the main corrosion assessment approaches today are, what quantitative risk assessment is or what methods are available for permanent and temporary repair. These are questions that I have put to myself and that have prompted me to produce a quick guide covering the full life cycle of pipelines, both onshore and offshore. About the author Working as a pipeline engineer, Duraid Alkazraji is a chartered engineer currently providing training services to Matthews Engineering Training.
Duraid Alkazraji has worked in the pipeline industry for a number of years, having joined the BG group on their graduate development programme, and then going on to work for Advantica, PII and Saipem UK. The initial stage of pipeline design is conducted before any work commences on the construction.
It is important that environmental and legal considerations are taken into account, for instance an environmental impact assessment should be carried out to satisfy appropriate authorities and regulations. Detailed design can then be started. Firstly, the diameter and inlet pressure are decided upon according to the maximum acceptable pressure drop along the length of the pipeline. Other design parameters will then follow, including choosing an appropriate wall thickness, material grade and coating method.
Finally, the maximum allowable operating stress will be decided upon according to the location of the pipeline route. The next stage then looks at pipeline manufacture and construction. Spools are manufactured using four main methods, with each manufacturing method generally varying in the pipe sizes available. Construction and land preparation stages must be started, which in the case of onshore pipelines involves a working corridor being created and a pipeline trench being dug to a depth of approximately 1.
In the case of offshore pipelines, the trench is prepared using a dredger. Finally, positioning of the pipeline can be done using S-lay and J-lay methods for offshore pipelines. Controlling the risks from failure is an important part of any integrity and management strategy. The two main risk assessment approaches used throughout the pipeline industry include quantitative and qualitative methods.
Following these earlier stages, the pipeline is ready to begin operation. Before the pipeline can be operated safely, pipeline design codes require that it is pressure tested. A general hydrotest is usually conducted to 1. The hydrotest will identify defects that may fail at the design pressure.
Current best practice is to utilize high-level pressure testing, which provides a hydrotest safety margin. The basic principle of this is that the higher the pressure test used, the smaller the defects that will remain. There are numerous types of defect that may be found in pipelines, such as internal corrosion, external corrosion, laminations, stress corrosion cracking SCC , cracks, dents and gouges. Consequently, it is important that pipeline operators utilize the most appropriate inspection methods available.
Currently, the most widely used methods include magnetic and ultrasonic inspection tools, but specialist inspection tools are available that can detect SCC, channelling corrosion and seam weld defects. There are various defect assessment approaches, all of which can be rather confusing, such as ASME B The main methods used throughout the industry have been summarized in this book, including effective area methods, UTS-based corrosion assessment, dent fatigue life estimation and how to assess WPNL xii Summary planar defects such as cracks and laminations using codes BS and API Finally, ongoing maintenance of pipelines should then form part of a failure prevention and corrosion monitoring strategy including ongoing repairs and surveying techniques.
This book describes the capabilities of each method and the various permanent and temporary repair methods used throughout the industry. This chapter will look at the initial stage of pipeline design for oil and gas pipelines.
Within the planning phase, and before any work commences on constructing a new pipeline, factors that affect the design process include:. There are currently numerous standards available that provide guidance on the design of pipelines. Some operators may use their own national standard, but many others use foreign standards that are widely used throughout the pipeline industry.
Within the UK, oil and gas pipelines are based on guidance provided by PD . A summary of the main standards used worldwide includes those shown in Tables 1.
Haviland Mancuso Shaft Alignment Handbook, John Piotrowski Adams Orthwein Trietley Murr, Karl P. Staudhammer, and Marc A. Meyers Magnesium Products Design, Robert S. Busk Engelke Jensen Fundamentals of Robotics, David D. Ardayfio Erickson Stan Wei Knox, with contributions by Thomas C. Boos, Ross S.
Culverhouse, and Paul F. Muchnicki Dukkipati and Joseph R. Amyot Mallick Juds Champion, Jr. Michael Ensminger Steele Tse and Ivan E.
Morse Karassik Hablanian Meyers, Lawrence E. Murr, and Karl P. Staudhammer Koelet Applied Combustion, Eugene L. Keating Bartz Murdock Bell and Douglas H. MacNeal Nielsen and Robert F. Landel Bayer South and Jon R. Handbook of Turbomachinery, edited by Earl Logan, Jr.
Monahan Schacht Meadows Friction Science and Technology, Peter J. Blau Pump Characteristics and Applications, Michael W. Volk Stewart Seireg and Jorge Rodriguez Cruse Speck It is more environmentally friendly. Lumkes, Jr. Is the dent plain? In developing a corrosion management strategy it is essential to determine if corrosion growth is occurring along the pipeline route.
Relating this to pipelines, factors that affect the likelihood of a corrosion cell occurring are: A standard hydrotest to 1. An alternative approach has been developed by Advantica, known as the Grouted2 tee connection. It is generally used as a temporary repair for leaking defects, and is usually replaced within a year following application.
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