Pipeline Stabilisation Using Pre-Trenching and Sand Backfill

2012 ◽  
Author(s):  
David J. Chamizo ◽  
Dean R. Campbell ◽  
Carl T. Erbirch ◽  
Eric P. Jas ◽  
Liang Cheng
Keyword(s):  
Natural Gas ◽  
Large Diameter ◽  
Mechanical Damage ◽  
Clay Content ◽  
Carbonate Sand ◽  
Natural Gas Pipelines ◽  
Limited Success ◽  
Wave Heights ◽  
Subsea Pipelines ◽  
Very High

Stabilizing large diameter natural gas pipelines on the seabed against extreme hydrodynamic loading conditions has proven to be challenging in the northwest of Australia. Tropical storms, which affect the area annually between November and April, can generate wave heights exceeding 30 m and on-bottom steady-state currents of 2 m/s or more. Consequently, in shallow water depths, typically less than 40–60 m, subsea pipelines can experience very high hydrodynamic loads, potentially causing significant lateral movement. If the seabed is rugged, or at locations where the pipeline approaches a point of fixity, this can lead to the pipeline suffering mechanical damage, which is undesirable. In many places on the Northwest Shelf of Australia, there is a layer of minimum 3 m deep marine sediments. The sediments predominantly comprise of relatively stable, fine to medium sized carbonate silts and sands, sometimes with some clay content. Traditionally, in Australia and other parts of the world, post-trenching techniques such as ploughing and jetting have been applied in such areas. These techniques can successfully lower the pipeline into the seabed. However, in many situations on the Northwest Shelf of Australia, post-trenching has had limited success. This has in part been due to the unpredictable levels of cementation of the carbonate sand, which has often resulted in an insufficient trench depth, with the need to implement costly and time consuming remedial works to ensure pipeline stability. The uncertainties in the success of post-trenching tools lead to the development of the pre-trenching and sand backfill method, which was first applied in Australia in 2003 on a 42-inch diameter natural gas trunkline. This technique has several advantages compared to post-trenching and other conventional pipeline stabilization methods such as rubble mound pipeline covers or gravity anchors. This paper presents an overview of the pre-trenching and sand backfill method, its design principles, benefits, and risks and opportunities.

Rock Berm Design for Pipeline Stability

2012 ◽  
Author(s):  
David J. Chamizo ◽  
Dean R. Campbell ◽  
Eric P. Jas ◽  
Jay R. Ryan
Keyword(s):  
Traditional Approach ◽  
Large Diameter ◽  
Mechanical Damage ◽  
Small Scale ◽  
Lateral Movement ◽  
Functional Requirements ◽  
Natural Gas Pipelines ◽  
Hydrodynamic Loading ◽  
Wave Heights ◽  
Subsea Pipelines

Stabilizing large diameter natural gas pipelines on the seabed against extreme hydrodynamic loading conditions has proven to be challenging in the northwest of Australia. Tropical storms, which affect the area annually between November and April, can generate wave heights exceeding 30 m and storm steady state currents of 2 m/s or more. Consequently, in shallow water depths, typically less than 40–60 m, subsea pipelines can be subjected to very high hydrodynamic loads, potentially causing significant lateral movement. To mitigate the risk of the pipeline suffering mechanical damage due to excessive lateral movement, quarried and graded rock is often dumped over the pipeline as a secondary stabilization solution. In order to satisfy functional requirements, the rock berm must comprise of a sufficiently large rock grading size and berm volume to withstand the design hydrodynamic loading such that the pipeline cannot break out of the berm. The design of rock berms for pipeline secondary stabilization has traditionally followed a deterministic approach that uses empirical equations for preliminary rock sizing, followed by small-scale physical modeling for design verification and optimization. Whilst the traditional approach can be effective in producing a robust rock berm design, opportunities for further optimization are inhibited by a lack of available data and an imperfect understanding of the failure mechanisms. This paper presents an overview of an improved approach for rock berm design optimization. A general overview of rock berms, the design principles, benefits and risks are also presented.

Basis of the New Criteria in ASME B31.8 for Prioritization and Repair of Mechanical Damage

2002 ◽  
Author(s):  
M. J. Rosenfeld ◽  
John W. Pepper ◽  
Keith Leewis
Keyword(s):  
Natural Gas ◽  
Safety Concern ◽  
Mechanical Damage ◽  
Operating Experience ◽  
Third Party ◽  
Detailed Review ◽  
Natural Gas Pipelines ◽  
Industry Research ◽  
Pipe Section ◽  
New Criteria

Mechanical damage in the form of dents has emerged as a key safety concern for pipelines. In response, ASME B31.8, with assistance from GTI, undertook a detailed review of industry research and operating experience with respect to various forms of mechanical damage. Revised criteria for prioritizing and effectively repairing damage in natural gas pipelines were developed based on the findings. The criteria address plain dents, third-party type damage, dents that affect weldments, dents affected by corrosion, and strain levels associated with deformation of the pipe section. This paper discusses the generalities of the scientific findings and basis for the changes to the Code.

scholarly journals Fracture Behaviour and Defect Evaluation of Large Diameter, HSLA Steels, Very High Pressure Linepipes

2000 ◽  
Author(s):  
G. Demofonti ◽  
G. Mannucci ◽  
L. Barsanti ◽  
C. M. Spinelli ◽  
H. G. Hillenbrand
Keyword(s):  
High Pressure ◽  
Natural Gas ◽  
Fracture Behaviour ◽  
Large Diameter ◽  
Transportation Cost ◽  
Current Status ◽  
Pressure Pipeline ◽  
On Line ◽  
High Pressure Pipeline ◽  
Very High

Actually, the increase in natural gas needs in the European market, foreseen for the beginning of the next century, compels to develop new solutions for the exploitation of gas fields in remote areas. For natural gas transportation over long distances the hypothesis of a large diameter high-pressure pipeline, up to 150 bar (doubling of the actual one) has been found economically attractive, resulting in significant reduction of the transportation cost of the hydrocarbon. In this contest the interest amongst gas companies in the possible applications of high-grade steels (up to API X100) is growing. A research program, partially financed by E.C.S.C. (European Community for Coal and Steel), by a joint co-operation among Centro Sviluppo Materiali (CSM), S.N.A.M. and Europipe in order to investigate the fracture behaviour of large diameter, API X100 grade pipes at very high pressure (up to 150 bar) has been carried out. This paper presents: the current status of technology of API X100 steel with respect to the combination of chemical composition, rolling variables and mechanical properties the results obtained from West Jefferson tests, in order to confirm the ductile-brittle transition behaviour stated from laboratory tests (DWTT), the results obtained concerning the control of long shear propagating fracture and in particular the results of a full scale crack propagation test on line operating at very high hoop stress (470 MPa). Besides, in order to investigate the defect tolerance behaviour of the pipe with respect to axial surface defect, burst tests with water as pressurising medium have been carried out and the relative results are presented and discussed.

scholarly journals Mechanical Development of a NPS 36 Speed Controlled Pipeline Corrosion Measurement Tool

1998 ◽  
Author(s):  
Robert S. Evenson ◽  
Scott K. Jacobs
Keyword(s):  
High Pressure ◽  
Natural Gas ◽  
Large Diameter ◽  
Speed Control ◽  
Measurement Tool ◽  
Gas Pipelines ◽  
Natural Gas Pipelines ◽  
Natural Gas Pipeline ◽  
System A ◽  
Flux Leakage

High pressure natural gas pipeline companies conducting in-line magnetic flux leakage (MFL) corrosion inspection operations had to significantly reduce gas throughput velocity to accommodate MFL corrosion tool inspection speeds. A large bypass, variable speed NPS 36 MFL corrosion inspection tool has been developed and run successfully in several high pressure natural gas pipelines without noticeable impact on operational throughput Active speed control enables the tool to run at speeds significantly lower than line velocity commonly experienced in high pressure natural gas pipelines. Unique mechanical innovations include large diameter flow bypass, an efficient speed control mechanism, variable drag backing bars and an independent bypass override system. A floating backing bar system ensures uniform sensor/wall contact for optimum data collection. Magnetic self-levitation of the backing bar results in reduced load on suspension and wheels providing more reliability and longer life to these components. Operating in higher line velocities infers higher possible tool speeds. This potential required development and construction of a more durable tool capable of higher speeds than typical MFL corrosion inspection tools. In this paper, development, testing and field operation of this tool is described.

Validation of EMAT ILI for Management of Stress Corrosion Cracking in Natural Gas Pipelines

2014 ◽  
Author(s):  
Toby Fore ◽  
Stefan Klein ◽  
Chris Yoxall ◽  
Stan Cone
Keyword(s):  
High Resolution ◽  
Natural Gas ◽  
Stress Corrosion ◽  
Stress Corrosion Cracking ◽  
Corrosion Cracking ◽  
Probability Of Detection ◽  
Gas Pipelines ◽  
Line Pipe ◽  
Natural Gas Pipelines ◽  
Electro Magnetic

Managing the threat of Stress Corrosion Cracking (SCC) in natural gas pipelines continues to be an area of focus for many operating companies with potentially susceptible pipelines. This paper describes the validation process of the high-resolution Electro-Magnetic Acoustical Transducer (EMAT) In-Line Inspection (ILI) technology for detection of SCC prior to scheduled pressure tests of inspected line pipe valve sections. The validation of the EMAT technology covered the application of high-resolution EMAT ILI and determining the Probability Of Detection (POD) and Identification (POI). The ILI verification process is in accordance to a API 1163 Level 3 validation. It is described in detail for 30″ and 36″ pipeline segments. Both segments are known to have an SCC history. Correlation of EMAT ILI calls to manual non-destructive measurements and destructively tested SCC samples lead to a comprehensive understanding of the capabilities of the EMAT technology and the associated process for managing the SCC threat. Based on the data gathered, the dimensional tool tolerances in terms of length and depth are derived.

Comparison of PIR to PIPESAFE-Based 1% Lethality Zones for Natural Gas Pipelines

2014 ◽  
Author(s):  
Aleksandar Tomic ◽  
Shahani Kariyawasam
Keyword(s):  
Natural Gas ◽  
Small Diameter ◽  
Gas Pipeline ◽  
Accurate Estimation ◽  
Simple Relationship ◽  
Gas Pipelines ◽  
Friction Forces ◽  
Natural Gas Pipelines ◽  
Decay Factor ◽  
Outflow Rate

A lethality zone due to an ignited natural gas release is often used to characterize the consequences of a pipeline rupture. A 1% lethality zone defines a zone where the lethality to a human is greater than or equal to 1%. The boundary of the zone is defined by the distance (from the point of rupture) at which the probability of lethality is 1%. Currently in the gas pipeline industry, the most detailed and validated method for calculating this zone is embodied in the PIPESAFE software. PIPESAFE is a software tool developed by a joint industry group for undertaking quantitative risk assessments of natural gas pipelines. PIPESAFE consequence models have been verified in laboratory experiments, full scale tests, and actual failures, and have been extensively used over the past 10–15 years for quantitative risk calculations. The primary advantage of using PIPESAFE is it allows for accurate estimation of the likelihood of lethality inside the impacted zone (i.e. receptors such as structures closer to the failure are subject to appropriately higher lethality percentages). Potential Impact Radius (PIR) is defined as the zone in which the extent of property damage and serious or fatal injury would be expected to be significant. It corresponds to the 1% lethality zone for a natural gas pipeline of a certain diameter and pressure when thermal radiation and exposure are taken into account. PIR is one of the two methods used to identify HCAs in US (49 CFR 192.903). Since PIR is a widely used parameter and given that it can be interpreted to delineate a 1% lethality zone, it is important to understand how PIR compares to the more accurate estimation of the lethality zones for different diameters and operating pressures. In previous internal studies, it was found that PIR, when compared to the more detailed measures of the 1% lethality zone, could be highly conservative. This conservatism could be beneficial from a safety perspective, however it is adding additional costs and reducing the efficiency of the integrity management process. Therefore, the goal of this study is to determine when PIR is overly conservative and to determine a way to address this conservatism. In order to assess its accuracy, PIR was compared to a more accurate measure of the 1% lethality zone, calculated by PIPESAFE, for a range of different operating pressures and line diameters. Upon comparison of the distances calculated through the application of PIR and PIPESAFE, it was observed that for large diameters pipelines the distances calculated by PIR are slightly conservative, and that this conservativeness increases exponentially for smaller diameter lines. The explanation for the conservatism of the PIR for small diameter pipelines is the higher wall friction forces per volume transported in smaller diameter lines. When these higher friction forces are not accounted for it leads to overestimation of the effective outflow rate (a product of the initial flow rate and the decay factor) which subsequently leads to the overestimation of the impact radius. Since the effective outflow rate is a function of both line pressure and diameter, a simple relationship is proposed to make the decay factor a function of these two variables to correct the excess conservatism for small diameter pipelines.

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