Designing Offshore Pipeline Safety Systems Utilising Flow and Pressure in Multi Design Pressure Pipeline Systems

2008 ◽  
Author(s):  
Gjertrud Elisabeth Hausken ◽  
Jo̸rn-Yngve Stokke ◽  
Steinar Berland
Keyword(s):  
Pressure Drop ◽  
Flow Measurement ◽  
Large Diameter ◽  
Pressure Sensors ◽  
Safety System ◽  
Pipeline System ◽  
Outlet Pressure ◽  
Pipeline Systems ◽  
Pipeline Safety ◽  
Design Pressure

The Norwegian Continental Shelf (NCS) has been a main arena for development of subsea pipeline technology over the last 25 years. The pipeline infrastructure in the North Sea is well developed and new field developments are often tied in to existing pipeline systems, /3/. Codes traditionally require a pipeline system to be designed with a uniform design pressure. However, due to the pressure drop when transporting gas in a very long pipeline, it is possible to operate multi design pressure systems. The pipeline integrity is ensured by limiting the inventory and local maximum allowable pressure in the pipeline using inlet and outlet pressure measurements in a Safety Instrumented System (SIS). Any blockage in the pipeline could represent a demand on the safety system. This concept was planned to be used in the new Gjo̸a development when connecting the 130 km long rich gas pipeline to the existing 450 km long FLAGS pipeline system. However, a risk assessment detected a new risk parameter; the formation of a hydrate and subsequent blockage of the pipeline. In theory, the hydrate could form in any part of the pipeline. Therefore, the pipeline outlet pressure could not be used in a Safety Instrumented System to control pipeline inventory. The export pressure at Gjo̸a would therefore be limited to FLAGS pipeline code. Available pressure drop over the Gjo̸a pipeline was hence limited and a large diameter was necessary. Various alternatives were investigated; using signals from neighbour installations, subsea remote operated valves, subsea pressure sensors and even a riser platform. These solutions gave high risk, reduced availability, high operating and/or capital expenses. A new idea of introducing flow measurement in the SIS was proposed. Hydraulic simulations showed that when the parameters of flow, temperature and pressure, all located at the offshore installation, were used; a downstream blockage could be detected early. This enabled the topside export pressure to be increased, and thereby reduced the pipeline diameter required. Flow measurement in Safety Instrumented Systems has not been used previously on the NCS. This paper describes the principles of designing a pipeline safety system including flow measurement with focus on the hydraulic simulations and designing the safety system. Emphasis will be put on improvements in transportation efficiency, cost reductions and operational issues.

Designing Offshore Pipeline Systems Divided Into Sections of Different Design Pressures

2004 ◽  
Author(s):  
Gunnar Staurland ◽  
Morten Aamodt
Keyword(s):  
Uniform Design ◽  
External Pressure ◽  
Transportation Systems ◽  
Point Of View ◽  
Pipeline System ◽  
Operating Pressure ◽  
Pipeline Systems ◽  
Upstream Pressure ◽  
Transmission Pipeline ◽  
Design Pressure

Norwegian waters have been a main arena for development of subsea pipeline technology over the last 25 year. The gas transportation systems from Norway to continental Europe comprise the largest and longest sub sea pipelines in the world. Codes traditionally require a pipeline to be designed with a uniform design pressure between stations with overpressure protection capabilities. However, the downstream part of a very long gas transmission pipeline may, after commissioning, rarely, if ever, see pressures near the pressure at the upstream end. There is, therefore, a potential for cost reduction and capacity improvement if two, or several, sections of different design pressure could be used without having to implement sub sea pressure regulation and overpressure protection facilities at the point of transition between the different sections of design pressure. In determining the lower design pressure the shutdown of the pipeline outlet facilities, at any point in time allowing for a practicable, achievable delay for closure of the upstream inlet valve has to be taken into account. The settle out pressure in a “normal” shut-in situation shall then not exceed the lower design pressure. In addition, deep water pipelines are often designed to withstand buckling due to bending and external pressure during installation, and may therefore locally tolerate a much higher internal pressure than the pipeline was designed for. Transmission pipelines crossing deepwater areas may therefore be designed for two or more operating pressures along the pipeline, thereby optimizing the cost. Even more important, for already existing pipelines, the capacity may be significantly increased by utilizing the upstream heavy wall sections. The operating pressure range for a long offshore gas transmission pipeline is very wide compared to an onshore line, typically between an upstream pressure of 150–250 bar, and a downstream pressure of 60 to 80 bar over a distance of several hundred kilometers. It may take hours to notice the closure of a downstream valve on the upstream pressure. Unless the pipeline is extensively packed, it is obvious that the pressure drop along the pipeline may be taken into account by allowing a lower design pressure for downstream part than for the upstream part. Thereby, the investment cost can be reduced. This paper describes the principles of designing a pipeline system divided into sections of different design pressures from a hydraulic point of view. The basis is the offshore standard for designing submarine pipeline systems, DNV OS-F101. The focusing will be on improvements in transportation efficiency, cost reductions and operational issues.

Gas Transmission Pipeline Safety and Integrity Activities and Results for INGAA Pipeline Companies

2012 ◽  
Author(s):  
Terry Boss ◽  
J. Kevin Wison ◽  
Charlie Childs ◽  
Bernie Selig
Keyword(s):  
Natural Gas ◽  
Management Practices ◽  
Pipeline System ◽  
Mandated Reporting ◽  
Pipeline Systems ◽  
Natural Gas Transmission ◽  
Transmission Pipeline ◽  
Integrity Management ◽  
Pipeline Safety ◽  
Transmission Pipelines

Interstate natural gas transmission pipelines have performed some standardized integrity management processes since the inception of ASME B3.18 in 1942. These standardized practices have been always preceded by new technology and individual company efforts to improve processes. These standardized practices have improved through the decades through newer consensus standard editions and the adoption of pipeline safety regulations (49 CFR Part 192). The Pipeline Safety Improvement Act which added to the list of these improved practices was passed at the end of 2002 and has been recently reaffirmed in January of 2012. The law applies to natural gas transmission pipeline companies and mandates additional practices that the pipeline operators must conduct to ensure the safety and integrity of natural gas pipelines with specific safety programs. Central to the 2002 Act is the requirement that pipeline operators implement an Integrity Management Program (IMP), which among other things requires operators to identify so-called High Consequence Areas (HCAs) on their systems, conduct risk analyses of these areas, and perform baseline integrity assessments and reassessments of each HCA, according to a prescribed schedule and using prescribed methods. The 2002 Act formalized, expanded and standardized the Integrity Management (IM) practices that individual operators had been conducting on their pipeline systems. The recently passed 2012 Pipeline Safety Act has expanded this effort to include measures to improve the integrity of the total transmission pipeline system. In December 2010, INGAA launched a voluntary initiative to enhance pipeline safety and communicate the results to stakeholders. The efforts are focused on analyzing data that measures the effectiveness of safety and integrity practices, detects successful practices, identifies opportunities for improvement, and further focuses our safety performance by developing an even more effective integrity management process. During 2011, a group chartered under the Integrity Management Continuous Improvement initiative(IMCI) identified information that may be useful in understanding the safety progress of the INGAA membership as they implemented their programs that were composed of the traditional safety practices under DOT Part 192, the PHMSA IMP regulations that were codified in 2004 and the individual operator voluntary programs. The paper provides a snapshot, above and beyond the typical PHMSA mandated reporting, of the results from the data collected and analyzed from this integrity management activity on 185,000 miles of natural gas transmission pipelines operated by interstate natural gas transmission pipelines. Natural gas transmission pipeline companies have made significant strides to improve their systems and the integrity and safety of their pipelines in and beyond HCAs. Our findings indicate that over the course of the data gathering period, pipeline operators’ efforts are shown to be effective and are resulting in improved pipeline integrity. Since the inception of the IMP and the expanded voluntary IM programs, the probability of leaks in the interstate natural gas transmission pipeline system continues on a downward slope, and the number of critical repairs being made to pipe segments that are being reassessed under integrity programs, both mandated and voluntary, are decreasing dramatically. Even with this progress, INGAA members committed in 2011 to embarking on a multi-year effort to expand the width and depth of integrity management practices on the interstate natural gas transmission pipeline systems. A key component of that extensive effort is to design metrics to measure the effectiveness to achieve the goals of that program. As such, this report documents the performance baseline before the implementation of the future program.

Flow-Induced Vibration of a Large-Diameter Elbow Piping Based on Random Force Measurement Caused by Conveying Fluid: Visualization Test Results

2005 ◽  
Author(s):  
Tomomichi Nakamura ◽  
Tadashi Shiraishi ◽  
Yoshihide Ishitani ◽  
Hisato Watakabe ◽  
Hiromi Sago ◽  
...  
Keyword(s):  
Force Measurement ◽  
Large Diameter ◽  
Pressure Fluctuations ◽  
Pressure Sensors ◽  
Maximum Flow ◽  
Axial Direction ◽  
Random Force ◽  
Test Facility ◽  
Flow Induced Vibration ◽  
Correlation Lengths

A 1/3 scale flow-induced vibration test facility that simulates the hot-leg piping of the JNC sodium-cooled fast reactor (JSFR) is used to investigate the pressure fluctuations of the pipe, where the high velocity fluid flows inside the piping. By the measurement of the pressure drop in the elbow piping while changing the Reynolds number, the similarity law of this model is confirmed. To evaluate the flow-induced vibrations for the hot-leg and cold-leg pipes, the random force distributions along the pipe and their correlations are measured with pressure sensors in a water loop. It is found that a flow velocity-dependent periodic phenomenon in the rear region of the elbow, and the maximum flow-induced random vibration force in the pipe are observed in the region of flow separation downstream the elbow. Finally, a design method is proposed with power spectral densities of the pressure fluctuations classified into four sections, correlation lengths in the axial direction divided into three sections, and with correlation lengths in the tangential direction into four sections.

How Do I Ensure “Staff Competency” in My Pipeline Safety Management System?

2020 ◽  
Author(s):  
Karen Collins ◽  
Michelle Unger ◽  
Amanda Dainis
Keyword(s):  
Management System ◽  
Cognitive Biases ◽  
Safety Management ◽  
Core Competencies ◽  
Pipeline System ◽  
Safety Management System ◽  
Key Skills ◽  
Learning Programs ◽  
Knowledge Requirements ◽  
Pipeline Safety

Abstract Standards and regulations are clear: all staff who work on pipelines need to be both “competent” and “qualified.” Standards such as API 1173 are clear about competence within a safety management system: “The pipeline operator shall ensure that personnel whose responsibilities fall within the scope of the PSMS [Pipeline Safety Management System] have an appropriate level of competence in terms of education, training, knowledge, and experience.” The burden of defining and specifying competence falls on pipeline operators, but they have little guidance regarding the required skills, knowledge and levels of competency. Additionally, we are all biased — different operators will have different ideas and emphases on competencies, which will affect their decision-making. The only way to avoid these cognitive biases is to use consensus standards supported by rigorous surveys that capture the required competencies. This paper explores some of the more common biases that can affect decisions and presents the results of a controlled, independent, survey aimed at both specifying and quantifying the necessary competencies needed by a specific engineer working within a PSMS: a pipeline integrity engineer. The paper identifies and ranks these necessary competences. The survey was completed by 100 pipeline integrity engineers from 25 different countries. Its specific objective was to investigate the key skills and knowledge requirements needed in a junior engineering position (i.e., a pipeline engineer with less than three years of relevant experience) working under supervision to be ‘competent’. It listed eight core competencies (identified by subject matter experts) considered essential for a pipeline integrity engineer. Each of these core competencies contained a set of skills. Respondents were first asked to rank the eight core competences, and then rank the skills within the competency. An analysis of the data provides insights into how 100 pipeline integrity engineers view the key skills required to be “competent.” The results of the survey can assist pipeline companies in setting objective competency requirements for their engineering personnel, developing learning programs to address any gaps, and improve the overall safety of their pipeline system.

Dynamic Stability Response of Piggyback Pipelines

2010 ◽  
Author(s):  
Hammam Zeitoun ◽  
Masˇa Brankovic´ ◽  
Knut To̸rnes ◽  
Simon Wong ◽  
Eve Hollingsworth ◽  
...  
Keyword(s):  
Stability Analysis ◽  
Dynamic Response ◽  
Dynamic Stability ◽  
Large Diameter ◽  
Hydrodynamic Forces ◽  
Model Testing ◽  
Equivalent Diameter ◽  
Pipeline System ◽  
Hydrodynamic Coefficients ◽  
Hydrodynamic Loads

One of the main aspects of subsea pipeline design is ensuring pipeline stability on the seabed under the action of hydrodynamic loads. Hydrodynamic loads acting on Piggyback Pipeline Systems have traditionally been determined by pipeline engineers using an ‘equivalent pipeline diameter’ approach. The approach is simple and assumes that hydrodynamic loads on the Piggyback Pipeline System are equal to the loads on a single pipeline with diameter equal to the projected height of the piggyback bundle (the sum of the large diameter pipeline, small diameter pipeline and gap between the pipelines) [1]. Hydrodynamic coefficients for single pipelines are used in combination with the ‘equivalent diameter pipe’ to determine the hydrodynamic loads on the Piggyback Pipeline System. In order to assess more accurately the dynamic response of a Piggyback Pipeline System, an extensive set of physical model tests has been performed to measure hydrodynamic forces on a Piggyback Pipeline System in combined waves and currents conditions, and to determine in-line and lift force coefficients which can be used in a dynamic stability analysis to generate the hydrodynamic forces on the pipeline [2]. This paper describes the implementation of the model testing results in finite elements dynamic stability analysis and presents a case study where the dynamic response of a Piggyback Pipeline System was assessed using both the conventional ‘equivalent diameter approach’ and the hydrodynamic coefficients determined using model testing. The responses predicted using both approaches were compared and key findings presented in the paper, in terms of adequacy of the equivalent diameter approach, and effect of piggyback gap (separation between the main line and the secondary line) on the response.

scholarly journals Experimental and Numerical Vibration Analysis of Hydraulic Pipeline System under Multiexcitations

2020 ◽  
Vol 2020 ◽  
pp. 1-13
Author(s):  
Peixin Gao ◽  
Hongquan Qu ◽  
Yuanlin Zhang ◽  
Tao Yu ◽  
Jingyu Zhai
Keyword(s):  
Pressure Fluctuations ◽  
Fluid Motion ◽  
Fluid Pressure ◽  
Point Of View ◽  
Pipeline System ◽  
Base Excitation ◽  
Fem Method ◽  
Pipeline Systems ◽  
Pump Pressure ◽  
Improved Model

Pipeline systems in aircraft are subjected to both hydraulic pump pressure fluctuations and base excitation from the engine. This can cause fatigue failures due to excessive vibrations. Therefore, it is essential to investigate the vibration behavior of the pipeline system under multiexcitations. In this paper, experiments have been conducted to describe the hydraulic pipeline systems, in which fluid pressure excitation in pipeline is driven by the throttle valve, and the base excitation is produced by the shaker driven by a vibration controller. An improved model which includes fluid motion and base excitation is proposed. A numerical MOC-FEM approach which combined the coupling method of characteristics (MOC) and finite element method (FEM) is proposed to solve the equations. The results show that the current MOC-FEM method could predict the vibration characteristics of the pipeline with sufficient accuracy. Moreover, the pipeline under multiexcitations could produce an interesting beat phenomenon, and this dangerous phenomenon is investigated for its consequences from engineering point of view.

Condition Assessment and Repair Prioritization of a Large Diameter Pipeline System

2019 ◽  
Author(s):  
Andrew F. Williams ◽  
Kristen A. Peterson ◽  
Peter D. Nardini ◽  
Rasko P. Ojdrovic
Keyword(s):  
Large Diameter ◽  
Condition Assessment ◽  
Pipeline System

Large Diameter Pressure Sensors: Design, Development and Sample Application

IFCEE 2018 ◽  
2018 ◽  
Author(s):  
Anne Lemnitzer ◽  
Lohrasb Keykhosropour ◽  
Antonio Marinucci ◽  
Steve Keowen
Keyword(s):  
Large Diameter ◽  
Pressure Sensors ◽  
Design Development ◽  
Sample Application

Experimental Study on Flow Boiling of HFC134a in a Multi-Port Extruded Tube

2004 ◽  
Author(s):  
Ken Kuwahara ◽  
Shigeru Koyama ◽  
Kengo Kazari
Keyword(s):  
Heat Transfer ◽  
Heat Transfer Coefficient ◽  
Pressure Drop ◽  
Transfer Coefficient ◽  
Flow Boiling ◽  
Rectangular Channel ◽  
Large Diameter ◽  
Local Heat Transfer ◽  
Local Heat ◽  
Inlet Temperature

In the present study, the local heat transfer and pressure drop characteristics are investigated experimentally for the flow boiling of refrigerant HFC134a in a multi-port extruded tube of 1.06mm in hydraulic diameter. The test tube is 865mm in total length made of aluminum. The pressure drop is measured at an interval of 191 mm, and the local heat transfer coefficient is measured in every subsection of 75mm in effective heating length. Experimental ranges are as follows: the mass velocity of G = 100–700 kg/m2s, the inlet temperature of Tin = 5.9–11.4 °C and inlet pressure of about 0.5 MPa. The data of pressure drop are compared with a few previous correlations for small diameter tubes, and the correlations can predict the data relatively good agreement. The data of heat transfer coefficient is compared with the correlations of Yu et al. proposed for relatively large diameter tubes. It is found that there are some differences about two phase multiplier factor of convective heat transfer between the circular channel and rectangular channel.

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