Offshore Pipeline design, analysis, and methods pdf

Contents List of Tables List of Figures 1 Introduction 1.22 Acquisitions of Rights and Permits 1.23 Exploration Phase 2 Hazards and Protection Concepts 3 Design Evaluations and Pipe Pa

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Offshore Pipeline

_ Design, Analysis, and Methods

PennWell Publishing Company

1421 South Sheridan Road/P O Box 1260 Tulsa, Oklahoma 74101

Library of Congress Cataloging in Publication Data Mousselli, AH

Offshore pipeline design, analysis, and methods

Bibliography Includes index

1 Petroleum in submerged lands—Pipe lines 2 Gas, Natural, in submerged lands—Pipe lines

I Title

TN 879.5.M64 665.5'44 80-—29039 ISBN 0—87814—156—1

All rights reserved No part of this book may be repro- duced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording, without the written

permission of the publisher

Printed in the United States of America

123 4 5 85 84 83 82 81

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Contents

List of Tables List of Figures

1 Introduction

1.22 Acquisitions of Rights and Permits 1.23 Exploration Phase

2 Hazards and Protection Concepts

3 Design Evaluations and Pipe Parameters

4 Installation Methods and Analysis

vi

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5.6 Trenching Regulations and Experiences

6 Pipe Connection and Positioning Systems

7 Subsea Pipeline Repair Systems

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8.31 8.32 8.33 8.34 8.35 8.36

Internal Pressure Water Temperature Contents Temperature Residual Tension Soil Friction Design Options

8.41 8.42 8.43 8.44 8.45 8.46 8.47 8.48 8.49

Amoco Montrose BNOC Dunlin Tie-In BNOC Thistle ELF/Norge Frigg Field

BP Forties Mobil Beryl and Statfjord OXY Piper Field Phillips Ekofisk Complex Shell Expro Brent System Bibliography

Pipe Properties Formulas Comparison of Pipelay Analysis Methods Major Underwater Trenching Machines Conceptual Evaluation of Trenching methods Offshore Pipeline Burial requirements Pipeline Trenching Experiences Comparison of Pipe Emergency Repair Methods

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Subbottom Profile Record Flow Diagram of Route and Weight Design Typical Pipeline Buckle Modes

Types of Buckle Arrestors Hydrodynamic Forces on Pipe Definition of Linear Wave Parameters Regions of Validity of Wave Theories Summary—Linear {Airy} Wave Characteristics Wave Length and Height Variations with Depth Drag Coefficient vs Reynolds Number Drag Coefficient for Different Keulegan-Carpenter Values Lift Coefficient vs Reynolds Number Vortex-Induced Oscillations Variations of Strouhal Number Strouhal Number vs Drag Coefficient Pipe Stability in Soils

Storm-Induced Bottom Pressures

xi

Soil Force Coefficient Soil Force Over 6-in Pipe Pipe Configuration Due to Low Depression Maximum Stress Due to Low Depression Stress at Midspan

Deflection at Midspan Induced Pipe Spans Pipe Due to Elevated Obstruction Span Due to Elevated Obstruction Maximum Stress Due to Elevated Obstruction Modes of Grain Transport

Current Velocity for Sediment Transport Conventional Lay Barge

Coated Pipe Joints Coated Field Joint Pipe Over Ramp Stern Ramp Support Diving Bell Diving Bell and Decompression Chamber Sectional Stinger for Large-Sized Pipe Floated Stinger Prior to Stabbing Stinger Drawbar Section Stinger Hinge

Stinger Roller Supports Conventional Lay-Barge Method Typical Tension and Stinger Variations F.B.D of Pipe String

Coated-Pipe Bonded Stiffness Stiffness Distribution Maximum Stress vs Assumed Stiffness Reel-Barge Method

Tow String Make-Up Yard Surface Tow

Below-Surface Tow RAT Method Off-Bottom Tow Bottom Tow Pipe-Trenching Definitions Jet Barge Illustration Spoil Removal by Compressed Air Sand Fluidization Burial Method

xii

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Gripper Grip and Seal Connector 142

Since the first offshore pipelines were laid in the Gulf of Mexico, thousands of miles of pipelines have been constructed offshore in various areas of the world, including the North Sea, the Gulf of Mexico, the Mediterranean, Australia, Southeast Asia, and Latin America Some pipelines were installed in water depths of nearly 2,000 ft Pipelines as large as 56 in in diameter were also installed A variety of construction equipment was used to install these pipelines, including the conventional lay-barge method, reel barge, and various pull and tow methods

As these installations were made in increasingly deep water, specialized technical and design problems had to be solved An offshore pipeline installed at any water depth must be designed such that it maintains its integrity during construction and during operating lifetime During construction, the pipeline is exposed to various bend-_

ing stresses as it is laid from the surface vessel to the seabed and due to lateral currents and various dynamic conditions After the pipe rests on the seabed, it is exposed to several potential risks of damage due to wave and current conditions in the area, soil instability, anchors, fishing trawls, and other hazards

After the pipeline size has been determined based on the flow conditions and friction characteristics, the pipeline-design work typically involves the evaluation of wave, current, and bottom conditions along the pipeline route from which selection of the pipe parameters can be made This involves the evaluation of soil strengths under static and

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2 | Offshore Pipeline Design, Analysis, and Methods

storm conditions and identification of the bottom features to define any slope-movement tendencies and limits of unstable areas

Pipe route is selected to minimize forces of possible soil movements

on the pipeline and to avoid any obstructions or hazards which may occur along the pipeline route Specifications of pipe material and specific gravities are made so that the pipe can resist hydrodynamic forces and maintain vertical stability during its lifetime The design work also typically involves analysis of the pipeline under operating conditions including pressure effects, thermal expansion, and storm loads on the pipe

Other considerations include selection of the most feasible and economic method for installing the pipeline and connecting it to an offshore facility These also include protection methods including trenching of the pipe below the seabed and riser installations In deep water and for relatively large-diameter pipelines, the design work also involves an analysis of the buckling characteristics of the pipeline under various conditions and specifications of buckle arrestors such that an accidental buckle is locally limited

This book provides an overview of the various principles and practices

of offshore pipeline design and methods This includes determination and evaluation of the various hazards, protection methods including trenching, installation methods and analysis of the various methods, buckling analysis and selection of the various pipeline parameters, connection methods and analysis, riser installation and analysis, operations analysis, and other specialized problems Design formulas are also presented wherever applicable Example problems are given to illustrate analysis and calculations of common submarine-pipeline design problems This provides the basic and various principles of offshore pipeline design in a concise manner and can be used as a reference book for basic designs of offshore pipelines

1.2 Overview of Oil and Gas Production

Offshore pipelines have an important role in the overall tasks of offshore oil and gas production A schematic diagram (Figure 1.1) shows the various aspects of this from the initial Stages of acquiring rights to search for oil and gas to the point where production of these hydrocarbons begins The various phases can generally be divided into four categories: (1) identification of prospect areas, (2) obtaining the rights for exploration, (3) exploration phase, (4) development phase, and (5} production and transportation phase

Introduction | 3

Identify prospects for exploration

| Drill exploratory well |

Start production

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1.21 Identification of Prospect Areas This phase defines the general geological areas where potential hydrocarbon prospects may exist This is usually based on an evaluation of the archeological and geological histories of the areas, with possible study of geophysical and seismic data of the areas

1.22 Acquisitions of Rights and Permits After preliminary searches to define potential areas of hydrocarbon reservoirs are completed, the right to drill exploratory wells in offshore tracts must be acquired from the various owners of these areas In the United States, these rights are usually acquired through successful bids

on specific tracts in an offshore lease sale conducted by the states for state-owned lands and by the Bureau of Land Management of the Department of Interior for the federally owned areas of the Outer Continental Shelf These rights can also be obtained from governments

in foreign countries by certain contractual agreements between the operating companies and the owner governments or national oil companies Often foreign governments have provisions to share in the hydrocarbons produced if they are found

1.23 Exploration Phase The operating company conducts various geological and geotechnical surveys in the area to assess the possibility of finding oil and gas in the specific tract If the survey data indicates that hydrocarbons may be found in the specific tract, then exploratory wells are drilled in the area

Exploratory drilling is usually done by various types of drilling rigs depending upon water depth in the area Jack-up rigs, which can be floated and towed to site then set on site for drilling, can be used in relatively shallow water In relatively deep water, other types of drilling rigs are used, including the ship-shaped drilling rig and the semisubmer- sible drill vessel These vessels can be moored in order to maintain position during drilling However, in very deep water, the mooring system is either supplemented or replaced by a dynamic positioning

After the drilling vessel positions on site, the casing pipe is driven below the seabed and cemented in place The blowout preventor stack is next installed in place to minimize risks of a blowout, which may occur

Introduction | 5 phase, various data can also be collected on the formations down the well hole After the exploratory well is drilled, other confirmation wells may also be drilled and further data may be gathered to estimate and confirm the oil and gas reserves which may be produced from the reservoir

1.24 Development and Production Phase After all information relating to the geological and geotechnical data

of the reservoir is analyzed and correlated with information obtained from exploratory drilling, technical and economic studies for develop- ing the field and producing the hydrocarbons begin These include an evaluation of alternatives for building an offshore fixed structure for drilling and producing, multiple structures for drilling and producing,

- subsea production systems with an offshore terminal, and other drilling _

or producing systems

Field-development studies are done to evaluate the various development alternatives and the time schedules and costs associated with these alternatives Other development options include a definition of the number of wells to be drilled, selection of the most feasible type of production facility, oil and gas processing, power-generation systems, and other operational factors Because of the cost and time involved in constructing an offshore producing facility, it is generally desirable to drill and produce using the same facility Simultaneous drilling and production is sometimes undesirable for safety reasons, and often there are separate structures for drilling and production

Various types of production facilities exist, including surface and subsea production systems The surface-production system typically is made up of a fixed offshore platform equipped with both drilling and production equipment Oil, gas, or both are transported to shore via submarine pipelines In other cases, the crude may be transported by a submarine pipeline to an offshore terminal then loaded to a tanker which then transports the crude to shore

The subsea production system typically is made up of a floating vessel which has both drilling and production equipment In the subsea production system, all drilled wells are completed on the seabed These wells are connected to and supported by a subsea template The crude is then transported by a submarine pipeline to an offshore terminal where

it can be loaded into a storage and a transportation facility The main advantages to subsea production facilities are that the production system is less costly than fixed platforms, it can be used in very deep water,

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6 | Offshore Pipeline Design, Analysis, and Methods and it provides earlier production than would have been obtained by a surface production facility The system is also desirable in remote areas and for marginal field developments

In certain cases where reservoir hydrocarbon deposits cannot be drilled and produced from the same surface producing facility, a combination of the surface production system and the subsea production system can be used In this case, the remote wells are serviced by a common subsea manifold Production risers then connect the subsea manifold to the surface production facility

If gas is found, a pipeline is required, although various schemes have been proposed for offshore use of gas-power generation, ammonia plants, etc If gas is associated with oil production, it must either be flared (usually illegal in large quantities}, used for process power, rein- jected, or pipelined to shore Development often proceeds in phases: (1) oil production/flare, (2) gas reinjection, and (3) gas production and transmission to shore

1.3 Types of Subsea Pipelines There are four general classifications of offshore pipelines, depending

on the line function Certain pipe sizes and operating pressure may also

be associated with each line classification These classifications are flowlines or intrafield lines, gathering lines or interfield lines, trunk lines, and loading (unloading) lines

1.31 Flowlines (Intrafield Lines)

A flowline connects a well to a platform or subsea manifold Usually the line has a small diameter and may be bundled Flow inside of it may

be at high pressure The flowline is used where reservoir pressure is sufficient to flow the fluid through the line without boost (pump or compressor)

1.32 Gathering Lines (Interfield Lines)

A gathering line connects from one (multiwell) platform to another platform and is usually a small- to medium-diameter line but can be large diameter, too The line may be a bundled oil, gas, condensate, or two-phase flow The range of operating pressure is usually between

Introduction | 7 sors which are often installed on the platform A gathering line may also transmit the product from a drilling platform to a separate production platform

1.33 Trunk Lines

A trunk line handles the combined flow from one or many platforms

to shore The line is usually of large diameter and can either be oil or gas

Booster pumps or compressors must be provided at intermediate platforms for very long trunk lines A trunk line is usually a common carrier, carrying product owned by many producers

_ 1.34 Loading (Unloading) Lines These lines usually connect a production platform and a loading facility or a subsea manifold and a loading facility The lines can be small or large diameter and carry liquid only Connection may be from a shore facility to an offshore loading or unloading terminal, as in the case

of the Louisiana Offshore Oil Port (LOOP)

Loading lines are usually short, ranging from 1 to 3 miles long, although in the case of LOOP, the unloading line is about 21 miles long

The loading facility may be temporary, such as an early production facility, to provide limited product shipment until a gathering or a trunk line can be completed The loading line can be used with a permanent loading facility for small reservoirs and in remote areas

Several considerations are usually made to determine the size of the pipeline These considerations include the type of hydrocarbon contents being pumped into the pipeline, throughput in the pipeline which

is the volume of contents to be transported by the pipeline, pump and compressor capacity at the pumping station, pressure losses along the pipeline length, and the pipeline-route details From all of these considerations, calculations can be made to size the pipeline so the required throughput is obtained with a minimum loss of energy

Determining the size of a submarine pipeline has many similar aspects to sizing an onshore pipeline The main considerations involve flow and hydraulic calculations to account for the friction losses between contents and the pipeline and to insure an efficient mode of transporting the contents to a given location Throughout this book, it will be assumed that the pipeline size has been determined, and other considerations will be analyzed regarding mechanical and structural

‘design of the submarine pipeline

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Hazards and Protection Concepts

2.1 Hazard Determination (Marine Survey) Various hazards with potential risks of damage to a submarine pipeline may exist along a proposed pipeline route These hazards are due to either natural causes or man-made activities and can be classified into three categories: (1) hazards which can occur during the construction period, (2) hazards which can occur after the pipeline has been installed on the seabed, and (3) hazards which can occur both during the construction period and during operations

Natural hazards are those caused by the environment, including wave and current forces which may cause pipeline instability at the seabed, unsupported spans, soil movements, and earthquakes Man-made hazards include dragging anchors, dropped anchors, fishing activities, and discarded objects left on the seabed such as sunken vessels or debris left by construction vessels

To minimize potential risks of damage to the pipeline, these hazards must first be identified in the specific site, then measures be taken to protect the pipeline from these hazards The protection methods include trenching the pipeline below the seabed, anchoring of the pipeline, increased concrete coating, and strengthening the pipeline A common way for protecting the pipeline is to trench it below the

To identify the hazards which may exist along a proposed pipeline route, data must be gathered regarding waves, surface and subsurface currents, bottom currents, soil conditions on the seabed, soil movement tendencies, and other data In areas where active offshore installations are made, environmental data can usually be obtained from government

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Hazards and Protection Concepts | 9

and public resources Various operating companies often have proprie- tary data for those areas In remote areas and where data is unavailable, a marine survey is made to gather such data

2.11 Purpose of Survey The objective of a marine survey is to:

= Establish an understanding of the general geotechnical activities in the area, including recent deposits

« Identify faults, volcanic activity, gas vents, movement tendencies, and depressions and obstructions which may be present along the proposed pipe route

= Assess the stability of the area sediments, including continuous erosion and deposits

= Determine water depth/bathymetry along the proposed route

= Determine subbottom features and stratigraphy along the route

# Obtain data on the environmental conditions in the area, including waves, surface currents, and bottom currents

2.12 Elements of Survey One principal element of a marine pipeline survey is continuous profiling of the seabottom conditions along the pipeline route This is usually done by (1) towing a device called a “fish” at some depth along the proposed route and continuously recording data on charts aboard the towing vessel, and (2) collecting discrete station surveys where data is gathered at local stations along the route This includes the deployment

of current meters, soil sampling, and collection of other pertinent data

2.121 Oceanographic Data The oceanographic survey gathers data on wind, wave, and current conditions existing along the proposed pipeline route This data repre- sents the environmental conditions during the construction period of the pipeline and during its operating lifetime Duration of the construction period is affected by many factors, including the pipe parameters, site characteristics, and the type of equipment and methods used for installation

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10 | Offshore Pipeline Design, Analysis, and Methods Generally, the most severe significant wave and steady-current com- binations which occur once per 100 years are used to define oceanographic conditions on the pipeline during its lifetime Similarly, the most severe combination of wave and steady current which may occur once during the construction season are used to define the oceanographic conditions on the pipeline during construction

Another important aspect of the environmental data is that information can be obtained which helps in determining operational limits of the constructing vessel, optimum periods for construction, and selection of the most feasible construction method

Characteristics of the most severe ocean waves which may occur once per 100 years can usually be obtained from published data Data to be used in the hydrodynamic-stability analysis of the pipeline include the direction of the deepwater wave, the significant period, and the significant height of the wave The significant wave height is the average of the highest one-third of the observed wave heights in a given wave population The maximum observed wave height usually corresponds

to the combined energy of several waves having different wave heights, directions, phase angles, and periods

2.122 Soil Investigations The purpose of obtaining soil samples is to identify the soil characteristics along the pipeline route These characteristics are used in the design of the submarine pipeline, including determination of resistance

of the soil to pipeline movement, soil-strength deterioration due to cyclic-wave loadings, trenching requirements if the pipe is to be trenched below the seabed, and load-bearing capacity of the soils

Soil properties needed for the pipeline design include the following:

« General classification of soils and the grain-size distributions of the soil samples

= Specific gravity of the soils

= Soil moisture content

= Consistancy or Atterberg limits

= Undisturbed shear strength of clayey soils

« Remolded (disturbed) shear strength or sensitivity

= Permeability

Various devices can be used for obtaining soil samples, including the

® Gravity corer, a device that consists of a weighted coring tube which relies on gravity to penetrate the seabed This method is not effective where gravel or rock materials are encountered on the seabed since the core penetrates very little in these materials

= Piston gravity corer (Modified Kullenberg), a device that consists

of a steel barrel (usually 10 ft long} with a plastic tube liner, core retainer, and a cutting bit at the lower end (Figure 2.1) The device is rigged with driving weights, usually 400—500 lb The sample-core length depends on the type of soils and varies from 10 ft in soft clays and silt to 8 ft in sand, and about 1 ft in stiff clay Little penetration,

if any, can be obtained in the case of rock sediments The device's operation is shown in Figure 2.2

® Drilled core sampler, a device that uses a drilled piston to obtain soil samples to a large depth below the seabed

« Vibrocorer, a device that is self-powered and capable of obtaining a 4-in diameter core of up to 20 ft long The driving force in the vibracorer is obtained from a vibrator motor housed in a pressure casing and driven through electrical cables supplied from the surface vessel

2.1 Soil piston corer

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2.2 Piston corer operation

= Grab sampler, a device used in unconsolidated-seabed settlements

The sampler is lowered to the seafloor where soil enters an enclo- sure in the sampler The sampler is then closed and returned to the surface

= Underwater cameras can also be used for visual examination of the seabed sediments, particularly clay outcrops and boulders

Hazards and Protection Concepts | 13 2.123 Echo Sounder/Bathymetry Data

Echo sounders are used to measure depth of the seafloor (water depth)

Several types of echo sounders are available Some have high precision for increased accuracy of depth measurements The principle of the echo-sounding instrument consists of transmitting a controlled high- frequency acoustic signal to the seabed from an underwater transducer

As the signal is reflected on the seafloor and received by the transducer, the time difference between initial transmission and the receiving period is measured accurately

After corrections and calibrations have been accounted for regarding the speed of the acoustic signal in water, depth of the transducer, and other conditions, the time difference can then be calibrated to produce the water depth at a particular station This typically is provided by a continuous depth plot as the survey vessel travels along the proposed route Water depth can be measured with an accuracy of + 0.1% to 1% of water depth, depending on precision of the specific instruments used

2.124 Side-Scan Sonar Method The principle of the side-scan sonar method (seafloor mapping) is based on sending a wide beam of discrete sonic pulses from a towed transducer fish (Figure 2.3) above the seabed The towed transducer emits these acoustic pulses which scan the seabed on either side of the transducer Reflections of these pulses from objects on the seabed

Reflected signals are recorded continuously on a chart aboard the towing vessel These signals represent reflections from various objects

on the seabed, such as gravel, outcrops, and pipelines The intensity of the reflected signal depends on the object from which it has been reflected For example, a signal representing a reflection from rocks would be darker than a reflection signal from sand

By studying the intensity of the reflected signals and images on the recorded chart, it is possible to interpret the sonar reflections in a geological manner and to estimate the size and height of various objects on the seabed The sonar fish is normally towed between 30 to

50 ft from the seabed An EG&G seafloor mapping recorder is shown in Figure 2.4

Valuable information for submarine pipelines can be obtained from the side-scan sonar records This information includes the following:

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2.4 Seafloor mapping recorder

= Identification of the various features on the seabed which may exist along a proposed route, including depressions, obstructions, rock outcrops, sand waves, and mud flows

= Position of pipe inside the trench if the pipe has been trenched

# Anchor scouring marks or trawl marks which may have occurred

in the vicinity of the pipeline route An example of the side-scan sonar record showing mud-flow features and the pipe is shown in Figure 2.5

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16 | Offshore Pipeline Design, Analysis, and Methods Hazards and Protection Concepts | 17

= Transceiver

= Paper graphic recorder

# Winch’ to accommodate faired cable

The subbottom profiling method is a continuous-reflection profiling technique which provides data on the geological structure and composi- tion beneath the seabed A controlled pulse of acoustic energy is emitted

velocity, which, in turn, means a change in the geological properties of the sediments Such changes are detected by the reflected signals and are recorded on a machine aboard the towing vessel By approximating the speed of the acoustic signal in these various geological sediments and measuring the times of reflections, depths of these different geologic interfaces can be determined

The type of sediments between the interface boundaries can then be interpreted based on a study of the continuous reflection profiling in correlation with soil coring samples obtained in the field An example of the subbottom-profiling system is shown in Figure 2.6 This system is made by Ocean Research Equipment Inc (O.R.E.) and consists of:

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2.8 Subbottom profile record

2.126 Magnetic Anomaly Detection The magnetometer is used for anomaly detection along a proposed pipeline route The method is based on detecting changes in the magnetic field caused by metal objects on the seabed This instrument can

be used to detect metal objects such as other pipelines or wrecked ships which may exist near the proposed pipe route A sensor is towed near the seafloor, and the unit is tuned to the local earth magnetic-field level

Ambient earth magnetic field and changes due to local anomalies are recorded on a continuous chart

2.2 Design and Protection Concepts

As stated earlier, an offshore pipeline resting on the seabed can be

these hazards depend on the pipeline-site location For example, in the Gulf of Mexico, Mississippi Delta area, the pipeline may be exposed to mud slides and turbidity currents as well as to potential severe storm action and other bottom instabilities In the near-shore areas, the pipeline is often exposed to high hydrodynamic forces if exposed on the seabed In other areas of the world such as offshore California, pipelines are designed considering earthquakes as well as faultings which may occur in the area

A flow diagram of the main design considerations for selecting the pipe weight and route and maximizing safety in potentially unstable seabottoms is shown in Figure 2.9 Special considerations of pipeline installations in unstable seabottoms are listed in Table 2.1

2.21 Route Selection Based on the above discussions for identifying the various hazards along a proposed pipeline route, the basic criteria in selecting pipeline routes, particularly in unstable seabottoms, include the following:

= Avoid bottom obstructions or possible pipe spans which may exist along the proposed route

«= Avoid other pipeline crossings whenever possible

= Avoid anchoring areas if present

= Minimize pipe length in unstable sea floors and route the pipe in a relatively more stable area, if these can be identified

= Avoid any mounded obstructions and depressions which may cause spans to the extent possible

ø In mud-flow areas, minimize any soil-movement risks of damage to the pipe by routing the pipe in such a way that it runs in the same direction as the mud flow This can be accomplished by having the pipeline routed in a direction perpendicular to the bottom depth contours

Other factors may also have to be considered in selecting the pipeline route, depending on the specific site area, including bottom faults, particularly in earthquake areas, rock outcrops, fishing-trawl activities, and, in certain areas, possible floating ice In addition, other considerations for selecting a pipeline route may include a study of the biologic activities in the area, including coral reefs, environmental aspects in the area, and economic trade-offs

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20 Offshore Pipeline Design, Analysis, and Methods

Side scan wo | Sub-bottom profiler tra | ~ ve |

Y

[identity potential hazards, crossings & obstructions |

Determine most Determine most Y

severe severe condition: candidat pipeline It in mud slide

during construction | | during life of | toute Should be selected to paraliel direction of side |

installation method | | (100-yr storm) y

| Determine generalized soil conditions and stratigraphy | along routes, -

Qươnghh deterorgtlon xo doing storm conditions

Potential of large soil movements and induced forces

pipe route if any

construction SGo ty uring operation, SGo SGroat < sa < SG sink

No

{s burial req due to other

Table2.1_ Special Considerations for Pipeline & Riser Installation in Unstable Areas

Route Selection

e Environmental design criteria

e Hazard evaluation Mud slides Soil liquefaction Spans Pipeline Design Hydrodynamic stability analysis

¢ Buckling analysis

@ Liquefaction/stability analysis

@ Thermal load/flexibility analysis

® Safety joint/valve recommendations

Specifications

@ Installation methods

e Burial recommendations

e Alternative bids Permit Application

® Design report

2.22 Pipeline Protection Methods Methods exist to protect the pipeline from risks of damage due to environmental and other hazards These include the following:

= Increase pipeline weight coating, wall thickness, or both

# Anchor the pipeline by using gravity anchors, screw anchors, or other types of anchoring arrangements

= Strengthen the pipe

= Bury the pipeline below the level of the seabed

= Provide engineered filling material over the pipeline, including gravel, concrete mats, and sandbags

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In most cases, the pipeline is buried below the seabed to protect it from these hazards However, in some cases burial may adversely affect the safety of the pipeline as was discussed earlier in areas of large soil movements As will be discussed in Chapter 5, burial of an offshore pipeline may also be mandatory by the regulatory authorities in certain water depths and areas offshore

In general, burial protects the pipe against wave and current actions, including hydrodynamic lift and drag, and scour Exposing the pipeline may be preferred in certain areas where mud slides occur over the pipe length, where earthquakes may be present producing high soil forces along the pipe length, and where faults may be present

By increasing the weight coating of the pipeline, the pipe may resist hydrodynamic forces due to current and wave action, and resist vibration effects due to vortex shedding The increased concrete coating, however, may complicate the installation operation and increase the cost of installing the.pipeline A systematic and balanced design procedure should be followed as outlined in Figure 2.9 to select the most feasible method for protecting the pipeline against existing hazards in a specific area

As will be discussed later, the pipeline may also be exposed to hazards

of damage during construction, such as increased bending stresses and the potential threat of buckling Selection of the installation parameters — and buckle design considerations are discussed in Chapter 3 Pipeline protection by burial is discussed in detail in Chapter 5

In general, submarine-pipeline design requires careful examination of the following design elements:

# Line sizing

# Route selection

= Hydrodynamic stability analysis (installation and operating lifetime)

® Soils liquefaction analysis (safe range of pipe specific gravity)

# Soils movement analysis (loads imposed on pipeline)

« Ice movement and scour data

= Pipe protection methods/burial requirements

= Pipe buckling analysis

= Thermal load/flexibility analysis (expansion loops, restraints, if any)

® Pipe lay analysis (vessel motions; tension, stinger requirements)

= Route plans and profiles

= Riser designs

= Connection tie-in safety joint designs

a Shore crossing design

= Permit applications, design report

# Specifications, materials, installation

23

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Although some of these elements may not fit in certain installations, most applications include evaluations of flow properties, hydrodynamic forces, internal pressure, vortex-induced pipe oscillation, pipeline-soils stability, pipe buckling, effects of large soil movements, geologic faults, bottom obstructions, and depressions which may induce spans of the pipeline

Design parameters are carefully determined so the pipe can withstand forces applied to it during construction, and during the operating lifetime Because the pipeline is filled and often buried below the mud line during operations, it can withstand more severe hydrodynamic forces during operation than during construction

During operation of the pipeline, other hazards must be evaluated, including storm-induced soils’ horizontal and vertical instability Also, connections to offshore risers or subsea tie-ins are designed such that operating stresses due to thermal expansions, internal pressure, and other loads remain within safe limits

3.2 Internal Pressure

After the pipe size has been determined, pipe-wall thickness is selected so the maximum tangential (hoop) stress due to internal Pressure does not exceed the allowable stress as outlined by American National Standard Code for Pressure Piping (ANSI B31.8, 1975} and minimum Federal Safety Standards for gas lines relating to transportation of natural gas by pipeline (Part 192, title 49, Code of Federal Regulations) These codes state that a design factor of 0.5 should be used for the riser and the pipeline near the platform and a design factor of 0.72 be used for pipe away from the platform For oil pipelines, the governing codes are ANSI B31.4 and part 195, title 49, Code of Federal Regulations

The hoop stress due to internal pressure (P) is given by:

=—— 3

Ơn 2t

( 1)

Where: o,, = hoop stress due to pressure P, psi

= internal pressure in pipe, psi nominal outside diameter of pipe, in

pipe-wall thickness, in

D

t

Design Evaluations and Pipe Parameters | 25

A temperature derating factor is used if the product temperature exceeds 250°F Also, a longitudinal joint factor must be used where applicable (not for seamless pipe)

3.3 Buckle Analysis

3.31 General

As pipeline installations moved into deep water, the problem of pipeline collapse caused by the increased hydrostatic pressure became significant Pipe collapse depends on many factors, including the pipe- diameter/wall-thickness ratio (D/t), stress-strain properties, initial ovalization (out of roundness), hydrostatic pressure, and bending moment in the pipe Axial tension was also reported to influence the collapse characteristics of the pipeline, although to a lesser extent than bending or hydrostatic pressure

Pipe buckling can be defined as the flattening or excessive ovaling of the pipe cross section The buckle can be “dry” where pipe does not rupture or “wet” where pipe ruptures and fills with water

3.32 Local Buckling The critical elastic buckling pressure of a theoretically perfect pipe (perfectly round with a constant thickness and flawless material) due to hydrostatic-pressure loading only is given by the following expression:

=2E t/t (3.2)

Where: P, = critical collapse pressure for perfect pipe, psi

E = elastic modulus, psi

v = Poisson’s ratio

D = pipe diameter, in

t = pipe-wall thickness, in

The critical elastic buckling pressure is valid fora perfect pipe witha very large D/t ratio (greater than 250) In practice, residual ovalization in the pipe is present, and significant deformation of the pipe surface may

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occur prior to collapse Hence, the hydrostatic collapse pressure is also a function of the yield properties of the pipe material

An expression for determining the critical buckling pressure of perfect pipe which accounts for the pipe yield stress is adopted from the Rules for the Design Construction and Inspection of Submarine Pipelines and Pipeline Risers by Det norske Veritas {DnVỊ, 1976 This critical buckling pressure (P,} is given by:

P =2o6,+forg,<2yY

P =2Y.L sit s2) |fere.>3Y +e ' 2 (3.3)

¥ = pipe specified yield stress (corresponding to 0.005 strain)

Computer programs have been developed by various organizations to predict the collapse pressure of pipe under the combined influence of pressure, axial forces, bending, and accounting of pipe out-of-roundness

An approximate expression for the critical combination of bending moment (M) and external pressure (P) is reported in the DnV code as:

+ — = 1

P = critical net external pressure when M = 0

D/t P,

3.33 Buckle Propagation Laboratory experiments on pipe buckling conducted by Battelle Columbus Laboratories in the early 1970s revealed a buckle phenomena referred to as a “propagating buckle.” This describes the situation where

a transverse dent (which may have been caused by excessive bending or

and propagates along the pipe, causing collapse of the pipe along its traveling length The driving energy which causes a buckle to propagate

is the hydrostatic pressure

The nature of a propagating buckle is that a greater pressure level is required to initiate a propagating buckle (called buckle initiation pressure, P,) than the pressure required to maintain propagation of the buckle (called buckle propagation pressure, P,} As a consequence to this,

a buckle initiated in an offshore pipeline propagates and collapses the line until the external pressure becomes equal to or less than the propagating pressure This assumes that pipe properties (particularly wall thickness) remain the same A number of propagating buckle modes have been reported from experimental studies These are shown

in Figure 3.1

Theoretical and experimental investigations were made by various organizations to study the buckle-propagation phenomenon and to determine the buckle-propagation pressure for offshore pipelines These studies have resulted in similar, rather simple expressions for calculating the propagation pressure (P,}:

It is interesting to note that the propagation pressure depends only on the pipe yield stress and on the D/t ratio and does not depend on the stress state of the pipe The nature of causing a buckle in the pipe depends on the pipe parameters as well as external forces applied on the pipe In contrast, the propagation phenomenon addresses the pipe- buckle traveling due to hydrostatic pressure after a buckle has been initiated

Trang 20

Ị Tabis 3.1 Buckle Propagation Pressure

Pipe Dit Ratio *P, = 6Y ( D ) TP, = 1.15 mY ( aa) % Difference

Note: 24-in OD perfect pipe and API X-60 Grade

“Formula after paper #OTC 2680, Offshore Technology Conference, Houston, 1976,

by T Johns, et al

+Formula after Det Norske Veritas (Dn), “Rules for Design, Construction and Inspection

of Submarine Pipelines,” 1976

sure (P,) This could damage a substantial length of the line and result in great economic losses It would also be very uneconomical to design the pipeline with sufficient wall thickness such that the propagation depth

depth along the pipe length Accordingly, means have been found to limit the length of damaged pipe by the use of buckle arrestors

In principle, the buckle arrestor is a segment of pipe stronger than the

Various types of external and internal buckle arrestors exist, including integral ring, welded ring, welded sleeve, heavy-wall integral cylinder, and grouted free-ring buckle arrestors These are illustrated in Figure 3.2 and are listed as follows:

| Flattening buckle

= Integral ring, a heavy-wall ring with the same ID and a greater OD than the pipe—the most-effective external type

= Welded ring, a sleeve welded onto the OD of the pipe

® Free ring, a sleeve which is slipped over the pipe The annular space

Trang 21

Design of buckle arrestors includes selection of the spacings of arrestors and arrestor parameters, including diameter, wall thickness, grade, length, and type of arrestor These parameters are selected such that a traveling buckle in the pipeline under hydrostatic pressure does

defined as the net hydrostatic pressure required to allow a traveling

safely greater than the expected hydrostatic pressure on the buckle

select the length spacings between buckle arrestors to equal the length

of pipe suspended free span However, selection of spacings and the number of buckle arrestors often depends on many factors, including ease of repair, evaluation of risks in the area, mode of installation, and other economic factors In many cases, buckle arrestors have been spaced at intervals of 400-500 ft along the pipe length, although

segments, depending on water depth Appropriate design criteria are

quirements of various water depths along the pipeline route A single

of many pipeline routes

3.2 Types of buckle arrestors

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The length of a buckle arrestor is selected so it is longer than propagating-buckle wave length and so the buckle does not penetrate the arrestor For this purpose, arrestors are classified into long and short Long arrestors are defined generally as those with a length-to-diameter ratio (L/D,) of 2 to 5 Arrestors of L/D, ratios of less than 1 are generally classified as short arrestors These ratios can range between 0.25 and 1

L/D, ratios of 1 to 2 can be classified as intermediate ratios

A long integral buckle arrestor, which consists of a thick pipe segment (tal, a length (L}, and a yield stress (Y,), can resist buckle propagation where the net hydrostatic pressure (P} is less than the cross-over pressure {equal to propagating pressure of the arrestor of this case):

P<6Y, (By (3.9)

a provided that the buckle arrestor is long and that D,/t, is less than 40

A long sleeve-type, free-ring external buckle arrestor which has a wall thickness (t,) and a yield stress (Y,) can resist buckle propagation where the net hydrostatic pressure (P) is less than the cross-over pressure The maximum allowable pressure for a long free-ring external buckle arrestor with a minimum annular clearance between pipe and arrestor ring (snug fit) can be conservatively estimated from the following expressions:

P=3 v.(9Jˆ+ ox (BY for B <3 D D

P=15 ¥(2£) for B>3 (3.10)

Where: @ = #

D = pipe outside steel diameter, in

tạ = arrestor wall thickness, in

D, = outside diameter or arrestor, in

Y =yield stress of pipe (at 0.005 strain}, psi

Ya = yield stress of arrestor (at 0.005 strain), psi Note that these formulas are valid for long-buckle arrestors and where a

buckle arrestors (shorter in length than the pipe diameter] are used, then the cross-over pressure will decrease

The free-ring buckle arrestor is more practical than the integral-type welded arrestor This eliminates the additional welding and any problems which may be associated with the welding The loose-ring sleeve should have a minimum clearance between it and the pipe so that the maximum potential of the buckle arrestor is realized; yet this minimum clearance should be allowed for ease of installation and to minimize additional stresses in the pipe during pressurization In practice, the free-ring arrestor is made with a slight annular gap, and grout material is then applied to fill this gap

3.4 Hydrodynamic Forces The submarine pipeline can be subjected to the combined effect of steady currents, oscillatory currents, and wave-induced forces while resting on the seabed To evaluate the stability of pipe due to these forces, a free-body diagram of these forces acting on the pipe cross section is shown in Figure 3.3 These forces include the following:

= Submerged weight of the pipe and the weight of the contents

# Combined drag force

# Combined lift force

@ Inertia force

® Friction resistance force between the pipe and the seabed

A brief review is first presented of the oscillatory surface-wave theories

Wave-induced particle velocity and acceleration near the seabed and bottom pressure can be calculated using these theories

A definition of the various parameters for a simple sinusoidal progres- sive wave is shown in Figure 3.4 The linear (Airy) wave theory can be used to describe oscillatory-wave characteristics where motions are small, i.e., where the wave amplitude is small Higher-order theories such

as Stokes’ 2nd, 3rd, 4th, and 5th-order theories can be used to predict more accurately wave characteristics for a wave having a large amplitude Also, long, finite-amplitude waves propagating in shallow water can best be described by Cnoidal wave theory Waves that are not oscillatory and do not exhibit a trough can be described by the solitary-wave theory Regions

of validity of the various wave theories are shown in Figure 3.5

To illustrate hydrodynamic-force calculations presented in this sec-

Trang 23

34 | Offshore Pipeline Design, Analysis, and Methods Design Evaluations and Pipe Parameters | 35

Free-stream velocity, U,

Ị y

Concrete coating Steel pipe

“ 6 x

Trough : 27x _ 27t NOTE: a) 7 =a Cos (SF itt) b) For given origin (x= 0) wave profile is shown

3.3 Hydrodynamic forces on pipe

3.4 Definition of linear wave parameters (after Shore Protection Manual, 1977)

tion, consideration is made of the linear, small-amplitude, oscillatory- wave theory Formulas for calculating the different wave characteristics

as a function of wave height, period, wave phase angle, and water depth are given in Figure 3.6

It is important to note that the deepwater significant wave height and wave direction change as the wave travels into shallow water due to combined effects of shoaling, refraction, defraction, friction, percolation, and reflections An illustration of the changes in the deepwater wave length (L,) is shown in Figure 3.7 for different water depths

So the pipeline remains stable on the seabed, summation of all forces on the pipe must satisfy the static equilibrium equation given by:

Where the symbols are described in Figure 3.3

If pipe is resting on the seabed with little embedment into the soil, then the lateral resisting force (F,} can be related to the normal force (N} by:

Trang 24

SHALLOW WATER e.ative gern uo Taansiionit mare

DEEP WATER

t <3 wct<t t>4

! Weve Preliie et " Her Ỹ cos < - zt) * $ cos 8

"

Shallow water Transitionat water

TP tre, ‘ h nos

3 Wore Longin litded scr to Se eon (=) trại ĐC rCạT

4 Ôreup Veleeiy cạ:c: /VE tyr aces [ie ST Te tee pcs Sh

š z

ae i H gf sion (2¥(24¢)/L) b} Vertieel et MZ ra hy ain nh sin 8 oh AH ae

‘ 6 Water Particle Acceterations

€) Horizontal «: TP SE sine ay aH HA thổ |4: zH(‡) et vua b) Vertieal a, = -2n (EY (4 £) cos Lưng TH TK cá 8 | 0 c~zH (‡) ett se

7 Woter Particle Displacements

b} vertices Ce Bete 2) cán 6 to smler reer) sa 6 tr! ttt cos 8

& Subsurface Pressure oO 2 pe (ner) pt een -ttth [27 2td)/L] par ceth(226/L) ot pane an par

calculated by adopting an expression derived by Morrison (1950) for

cylinder These forces are given by:

Where y is the lateral friction coefficient between pipe surface and the seabed

Combining equations 3.11 and 3.12 and using Equation 3.13 yields:

F› = +pC,DU: (3.17)

Trang 25

effective horizontal water-particle velocity over pipe height, ft/sec

horizontal water particle acceleration

Cp = hydrodynamic drag coefficient

Cụ = hydrodynamic inertia or mass coefficient

The 1/7th power law is commonly used to approximate the horizontal velocity profile (U) versus depth in the boundary layer:

u, 7) 3.19)

Where: U = horizontal particle velocity at a

height y from the seafloor in the boundary layer, ft/sec

velocity at height y,, ft/sec

As stated above, U, is usually calculated in the free stream at about 1m above bottom In reality, depth of the boundary layer depends on the bottom roughness and flow Reynolds’ number

The effective velocity (U,) to be used in Equation 3.17 can be obtained from the following averaging expression:

2.0r

1.0 0.8 0.6

Trang 26

Substituting Equation 3.19 in Equation 3.20 yields the following:

on the flow Reynolds numbers and roughness of pipe surface The Reynolds number is defined by the following:

Vv Where: »y = kinematic viscosity of the fluid about

1.0 x 10° ft?/sec for sea water) Pipe roughness coefficient (k} is defined as:

k ==, in/in

D Where: e = height of roughness Extensive measurements have been made for finding the drag coefficient in a unidirectional, steady-state flow over a pipeline and for nonsteady flows Drag coefficients were measured as a function of the Reynolds number Results are shown in Figure 3.8 Generally, the drag coefficient varies from 0.6 to 2.0, depending on the flow Reynolds number

Although drag coefficients have been measured for steady flows, these results are usually used for oscillatory flows associated with waves by selecting the maximum value of the combined current and wave-induced velocity over the pipe section Because velocity of the flow varies over the pipe diameter due to boundary-layer effects, the effective velocity is used

to evaluate the flow Reynolds number then to determine the corresponding drag coefficient

Experiments to measure drag coefficients for a wave-induced oscilla-

3.8 Drag coefficient vs Reynolds number (after Jones)

Reynolds number, pipe roughness, as well as the Keulegan-Carpenter number (K}, which is defined as:

Where: T = oscillatory wave period, sec

An illustration of the variation of drag coefficient with Reynolds number for constant values of K is shown in Figure 3.9 This can also be used to determine the drag coefficient for a particular application How- ever, use of Figure 3.8 for determining the drag coefficient is adequate for offshore pipeline design

Experiments have also been conducted in the past for measurements of

Trang 27

2.0 1.8Ƒ 1.6

1.44

1.2 1.0

3.9 Drag coefficient for different Keulegan-Carpenter values (after Sarpkaya)

of the lift coefficient (C,) and the inertial coefficient (Cy) The lift coefficient also depends on the Reynolds number and pipe roughness coefficient (k) for a steady-state flow The lift coefficient (C,} depends on the Reynolds number as well as the Keulegan-Carpenter number (K) for oscillatory flows Variation of the lift coefficient versus the Reynolds number for steady-state flows is shown in Figure 3.10

Investigations of the inertia coefficient (Cy) for a nonviscous, acceler- ated fluid flow over a pipeline have shown that the mean value of Cy generally varies from 1.5 to 2.5, depending on the flow Reynolds number

Based on the above discussions, recommended values of the hydrodynamic coefficients, (Cp), (C,), and (Cy), to be used for calculating hydro-

3.10 Lift coefficient vs Reynolds number

Table 3.2 Recommended Coefficients for Pipe Design (Exposed Pipe)

Trang 28

Effective combined particle velocity = 1 ft/sec

Calculate hydrodynamic coefficients for pipe design

Solution:

Calculate Reynolds number:

Re= UD

= 1.0 x 24

1.0 x 10° x 12

=2 x 105 Therefore:

The coefficient of friction between pipe surface and the soil must also

be determined to calculate the lateral soil-resisting forces on the pipeline

This coefficient of friction depends on the surface coating of the pipe and the bottom soil characteristics The friction coefficient also depends on the depth of embedment of the pipeline in the soil

In reality, when pipe is resting on the bottom, the soil below the pipeline deforms slightly As the pipeline moves laterally, soil fails underneath the pipeline and further lateral movement of the pipeline would cause the soil to deform laterally, thereby increasing the resisting forces to the pipe movement

Experimental measurements in the past have indicated that the coefficient of friction between the pipe and the seabed soil can vary between 0.5 to 0.9, depending on the pipe coating and the type of soil In general, the following coefficients of friction are used between concrete-

EXAMPLE PROBLEM:

Given:

Significant wave height, H, = 10 ft Significant wave period, T = 10 sec Water depth, d = 100 ft

Wave direction is normal to pipe axis Pipe OD = 1 ft

Seabed slope = 0 Assume a clay bottom with = 0.5 Solution:

A Check if linear theory is valid:

Trang 29

From Figure 3.7, the corresponding d/L is:

4 = 0.225

and the wave height ration due to shoaling effects is:

H

Hệ =0.92 From these, the wave length and wave height at d = 100 ft are:

F Substituting in Equation 3.17, the drag force is:

This term vanishes at t = 0

In general, both the drag force and inertial force must be evaluated at a given time and added to yield the combined drag forces on the pipe The maximum combined drag forces would be used in Equation 3.16 to determine required pipe submerged weight In this example, it is assumed that the maximum combined drag forces occur at t = 0, and thus this maximum force equals Fp

G Now substituting in Equation 3.16 for a level seafloor, the required pipe submerged weight is:

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H If other effects are significant, i.e., refraction, then these should be considered in calculating shallow-water wave parameters

3.5 Vortex-Induced Oscillations When water currents flow across the pipeline, vortices (eddies) occur downstream from the pipe These vortices are caused by the flow turbulence and instability behind the pipe Vortex shedding causes a periodic change in the net hydrodynamic pressure on the pipe, which may cause a pipe span to vibrate

Frequency of the vortex shedding depends on pipe diameter and the flow velocity If the vortex frequency, also referred to as Strouhal frequency, is synchronized with one of the natural frequencies of the pipeline span, then resonance occurs and the pipe span vibrates Pipe damages have been reported due to vortex-induced oscillations in the pipeline

Pipeline oscillations may occur in the cross-flow direction and the in-line direction of the flow By far the more serious oscillations are those which occur in the cross-flow direction In-line oscillations are not generally considered to cause serious oscillation problems in the pipe, although some exceptions to this have been reported Vortex- induced pipe oscillations are illustrated in Figure 3.11

Pipeline failures which may be caused by vortex-excited motions can

be prevented if the vortex-shedding frequency is sufficiently far from the natural frequency of the pipe span such that dynamic oscillations of the pipe are minimized The vortex-shedding frequency is given by the following:

,=<0 (3.25)

Where: f, = Vortex-shedding frequency, cps

S = Strouhal number

V = Flow velocity, ft/sec

D = Diameter of the pipeline, ft The Strouhal number is a function of the Reynolds number of the flow, as shown in Figure 3.12 The drag coefficient is also a function of the Reynolds number which, in turn, is a function of the water flow

_ C {El

Trang 31

3.12 Variations of Strouhal number

Where: EI = Pipe stiffness, lbs-ft’

a vortex-induced oscillation in the pipe span

Previous studies have shown that the vortex-excited oscillation of the pipe span is a function of the reduced velocity (Va), defined by:

Where: V = Flow velocity, ft/sec

f, = Natural frequency of the pipe span, cps

D = Pipe diameter, ft These studies also have shown that a pipe span starts to oscillate in line with the flow when the shedding frequency is about one-third of the natural frequency of vibration of the pipe span This corresponds to a value for the reduced velocity of about 1.3 As the flow velocity increases to higher levels, then cross-flow oscillations begin to occur, and this corresponds to a reduced velocity of about 5 In this case, the natural Frequency of the pipe span equals the vortex-shedding frequency of the

ow

For design purposes, it is customary to maintain the value of the reduced velocity to less than 3.5 (corresponding to a ratio of the vortex- shedding frequency to pipe natural frequency of 0.7) Vortex-induced

Trang 32

oscillations in the pipe were not observed for vortex-frequency values where:

C Pipe-span natural frequency for simply supported ends:

Pipe unit weight in air = W, = + (D?-D*,] x p, g Where: p, g = weight density of steel

ipe uni = M, = ——2— (12.75? — 11.752) 490_

= 2.03 slug/ft Displaced mass (assumed equal to added mass}

and pipe is safe from vortex excitations

3.6 Pipeline-Soil Stability Analysis Vertical and horizontal pipeline stabilities need to be carefully examined when pipe is resting on the seabed or embedded in the soil

These stabilities must be analyzed under static conditions as well as under cyclic pressure conditions caused by passage of a surface wave

3.61 Settiement and Flotation When a pipeline is partially or totally buried, it may float upward or settle downward under storm conditions, depending on the pipe weight (including contents}, soil density, and undrained shear strength of the soil (see Figure 3.14)

Various experiments have been made to measure soil flotation and

Trang 33

/\⁄

W = Submerged weight of pipe

3.14 Pipe stability in soils

resistance forces Based on these studies (Ghazzaly, 1975}, a range of pipe specific gravities may be selected such that the pipe is stable The following equations have been adopted to determine such a design range

Equivalent soil density = weight density of pipe and

Where: R = Soil resistance to flotation or settlement

per unit volume of pipe, lb/ft?

C = Remolded cohesive shear strength

of the soil, lb/ft?

D = Outside diameter of pipe, ft

If both sides of Equation 3.30 are divided by p, the density of water, then the upper and lower limits of the pipe specific gravity required for equilibrium can be calculated from:

Trang 34

In general, determination of the potential soil-strength reduction when subjected to storm-wave stresses on the seabed requires knowl- edge of the wave time history and the strength characteristics of the soil

Laboratory measurements have been made in the past (Lee and Focht, 1975) to determine the cyclic stress and uniform number of cycles (S-N curves) which cause soil failure Soil failure may be defined in terms of a cyclic strain amplitude Other factors, such as the cyclic-load shape and frequency, soil stress-strain relationship, and soil permeability, have also been determined to influence the soil S-N curve

Previous studies have indicated that the deterioration of soil strength when subjected to cyclic loading depends on the generation of excess pore pressure Generation of this pore pressure is basically strain depen- dent; hence, soil failure can be defined in terms of the cyclic strain amplitude

In sand, the pore pressure may build up to a level equal to the vertical effective stress, quickly causing sand liquefaction Thus, the failure potential for sand is commonly evaluated based on the ratio of the cyclic excess pore pressure to the vertical effective stress

Because of the relatively low permeability of clay, accurate pore- pressure measurements require very slow rates of cyclic loadings, and most cyclic tests on clay do not include any pore-pressure measurements Thus, failure criteria for clay are commonly defined in terms

of a cyclic-strain amplitude caused by cyclic-stress loadings

A storm wave is composed of an infinite number of frequencies, and concepts have been developed to express the effects of irregular cyclic loadings on soil in terms of an equivalent number of uniform cycles of

an average corresponding cyclic stress

After determining the potential and extent of soil-strength deterioration, pipe specific gravities may be selected such that the pipe remains stable in the weak soil As general criteria, pipe in unstable soils should

be designed such that its unit weight is close to the unit weight of the liquefied soils

3.7 Effects of Large Soil Movements Several mechanisms have been reported to cause soil movements at

Design Evaluations and Pipe Parameters | 57 soil depositions on steep slopes, and passage of large surface waves

Actual field measurements have been reported on vertical and lateral wave-induced movements of fine-grained sediments

The mechanism of the interaction of ocean waves and large movements of underwater slopes in soft, underconsolidated sediments is complex Efforts made to explain this mechanism have resulted in partial explanations due to the various simplifying assumptions made

In general, gravity forces acting alone on sloped bottoms are not sufficient to cause a mud slide However, gravity forces, when combined with cyclic wave loadings on the bottom sediment, can cause large soil movements

Wave forces on the seabed can cause sediment instability in two ways

First, as a result of the cyclic stresses and increased pore pressure caused

by the traveling wave, the soil shear strength may be greatly reduced and gravity forces may be sufficient to cause slope movements Second, the differential loading caused by the wave on the seabottom will induce stresses in the underlying soil If these stresses exceed the soil strength, significant soil movement may occur

Finite element analyses have been used (Wright, 1976) to calculate wave-induced seabottom movements, where the effect of gravity, cyclic and permanent soil movements were considered A hyperbolic, nonlinear stress-strain relationship has been assumed, but no strain rate or history effects have been included

A more recent analytical model was developed (Schapery and Dunlap, 1978) to predict storm-induced seabottom movement using viscoelastic analysis This model accounted for the soil inertia, nonlinear material damping, rate dependence of the soil properties, and down-slope movements induced by wave action However, the model assumes a sinusoidal water-wave train at the sea surface and does not account for the additional energy provided to the wave during its travel due to wind

Analyses and experimental measurements have been made for determining wave-induced soil movements and the consequent forces on

a buried pile (Marti, 1976) Based on laboratory measurements of soil- movement-induced forces on a pile, the following relationship is derived to calculate such forces which can be adopted to calculate dynamic soil-movement forces on a buried pipe:

F = 11.42 (125.9 nỊ" (V/D}* C, D 3.33]

Where: F = Dynamic soil force per unit length of pipe, lb/ft

D = Pipe diameter, ft

Trang 35

Where: F = Ultimate soil static force, lb/ft

C =Cohesive (disturbed) shear strength, psf

The bearing-capacity factor is a function of the depth of pipe embed-

This is shown in Figure 3.17 for a given soil sample

Therefore, the pipe should be placed at or slightly below the seabed to

resistance, analysis can be made to calculate stresses in the pipe induced

failure under soil loadings would depend on the pipe strength, soil forces which increase with depth, and the width of the mud slide

resisting the pipe movement and the extent of the slide width If the

resisting general movement of the pipe, then a localized bending failure

Since soil-movement forces on the pipeline are minimum when the pipe is placed on the seabed, a pipeline installed in unstable bottoms should be designed such that it remains on or slightly below the seabed

Trang 36

the bottom irregularities by methods such as presweeping These meas-

Therefore, to plan the installation procedure properly, an accurate prediction of pipe stresses due to bottom irregularities is necessary

200

3.81 Stresses Due to Low Depressions

0 L l l l i Í 1 j

3.17 Soil force over 6-in pipe

during its lifetime This will minimize any risks of damage to the pipe due to mud slides

However, when the pipe is not buried, it is exposed to hydrodynamic forces on the bottom Therefore, the pipe specific gravity must be selected such that the weight of pipe (including contents} is heavy enough for the pipe to remain stable under the most severe wave and current conditions during its lifetime, yet light enough that the pipe does not embed itself below the mud line

3.8 Effects of Seabed Irregularities During installation of a submarine pipeline, the pipeline may cross elevated obstructions or lowered depressions along its route As these bottom irregularities are crossed, spans and bending stresses will be induced in the pipe that must be maintained at a safe level to prevent

measures must be taken either to alter the pipeline route or to minimize

3.18 Pipe configuration due to low depression

Trang 37

shown in Figure 3.18 Boundary conditions are matched appropriately between each two adjacent pipe segments

Results of the computer analysis may be described in terms of dimensionless parameters for application to general problems Varia- tion of the maximum bending stress versus the depression span is shown for various values of pipe tension in Figure 3.19 Similarly, stresses as well as deflections at midspan are depicted in Figures 3.20 and 3.21, respectively Note that the maximum stress occurs at the boundary of the low depression

An examination of these figures reveals that these stresses decrease as the pipe tension is increased In particular for large-depression spans, inclusion of tension substantially reduces pipe stresses Length of the pipe span induced outside the depression is also depicted as a function of the depression span and tension in Figure 3.22 These pipe spans decrease in length as the pipe tension is increased Similarly, it is observed that, for large-depression spans, inclusion of tension reduces lengths of induced spans outside the depression

3.82 Stresses Due to Elevated Obstructions Consider the pipe configuration, over an elevated obstruction as shown in Figure 3.23 Let the elevation of the obstruction be 5 and the induced suspended pipe span be L A free-body diagram of the pipe forces

is shown in the same Figure 3.23 Since the pipe span is symmetric about the obstruction, it is sufficient to consider half the pipe span for the bending analysis

The pipe-governing equations are solved employing familiar numeri- cal techniques Because the span length is not known a priori, iterative procedures are employed to deduce this span length and pipe forces

Results of the solutions are then presented in terms of dimensionless parameters described earlier

Graphs depicting variations in induced pipe spans and resulting maximum stresses versus elevation of the obstruction are shown in Figures 3.24 and 3.25, respectively It is observed that maximum bending stresses caused by elevated obstructions are virtually unaffected by variations in pipe tension In contrast, pipe spans are increased as the pipe tension is increased It is noted, however, that tensile stress and combined bending and tensile stress will increase when tension in the pipe is increased Figures 3.24 and 3.25 allow for direct calculation of induced spans and maximum pipe stresses for a wide range of obstruction heights and various tension values

1.0 0.9

0.8 0.7

-C = Pipe outer radius

3.19 Maximum stress due to low depression

1.0 0.9

0.8 0.7 0.6 0.5 0.4 0.3 0.2

- C = Pipe outer radius § =0

3.20 Stress at midspan

63

Trang 38

14L 1⁄2 1.0F 0.8E- 06ƑE 0.4L 0.2Ƒ

8 =10

J | 4 ! 1 0.5 1.0 15 2.0 2.5 3.0 3.5 Dimensionless span =

3.23 Pipe due to elevated obstruction

Trang 39

Given:

Pipe = 16 in OD x 0.75 in W.T

Pipe weight = 35 lb/ft Calculate the following:

1 Maximum bending stress for a pipe over a span of 500 ft and having _ a tension of 65 kip

2 Maximum bending stress for a pipe over an elevated obstruction of

Design Evaluations and Pipe Parameters | 67 Solution:

The first step is to compute the characteristic length (L,}, characteristic stress (ơ.}, and dimensionless tension (8):

W = Pipe submerged weight lb/ft

C = Pipe outer radius, ft

T = Axial tension, Ibs Desired unknowns are now directly read off:

1 For a span of 500 ft, the dimensionless span length is given by:

L += 2.72

L eC The corresponding value of maximum dimensionless stress for B =

10 is read off Figure 3.19 as:

2m = 0.23

Oc

Therefore, maximum stress o,, = 25,000 psi

2 For an obstruction elevation of 10 ft, dimensionless elevation is given by:

é

©

The corresponding value of maximum dimensionless stress for

B = 10 is read off Figure 3.25 as:

Trang 40

Therefore, maximum stress om = 35,870 psi

Table 3.3 Pipe Properties Formulas

D_ = outside diameter of steel pipe, in

D, = inside diameter of steel pipe, in

tạ = thickness of corrosion coating, in

ty = thickness of weight coating, in

W.s = steel weight in air, lb/ft W.c = corrosion coating weight in air, lb/ft

Waw = weight coating weight in air, lb/ft

W, = pipe weight in air, lb/ft B= buoyant force, lb/ft

W, = submerged weight of pipe, lb/ft

I =bending moment of inertia of steel pipe, in.4

EQUATIONS

Wa: = 2.68 (D? — D,?)

Wace = see ((D + 2t.)? — D*), pe = Corrosion coat density, lb/ft?

Waw = ae ((D + 2t, + 2ty)? — (D+2t.)?), pw = Weight coat density, Ibvft?

Wa = Was + Wace + Waw

The mechanism of soil erosion is complex and is related to soil properties Considerable research has been conducted in the past on sediment transports due to water flow above river beds Much of this research is in general agreement on the initiation of motion of sediments consisting of sand, silt, or gravel The initiation of motion of sand requires less current velocity than that needed for the initiation of motion of clay particles This is due to the cohesion between the clay particles

To illustrate this phenomenon, consider a flat-bottom seabed con- taining sand with water flowing above it When the velocity is low, the seabed particles will not move As the flow rate is gradually increased, sediment grains begin to move (the sequence of this movement is illustrated in Figure 3.26)

Initially, the movement consists of random rolling and sliding of individual grains As the flow rate increases, turbulence increases near the seabed, and more particles roll and slide near the seabed This first incipient motion is referred to as the threshold of particle movement on

a flat seabed As the flow rate is increased, more particles move, with some lifted off the seabed for a short trajectory before falling back on the seabed The transportation of matter in this way is sometimes referred

to as siltation of sediments

As the flow becomes more turbulent, some of the sediment particles will be lifted increasingly higher above the seabed until they are in suspension and can be transported with the flow The more turbulent the flow is, the more particles are in suspension At very high flow rates, the flow will cause irregularities on the seabed known as ripples The suspended particles are free to travel in the mixed flow until the velocity decreases to a level such that the particles cannot remain in suspension any longer This velocity is known as the settling velocity

The minimum flow velocities for particle erosion, suspension, and settlement depend on the soil properties, including grain size and specific gravity However, the variation of specific gravity is small since most of the sediment particles are quartz with an immersed specific gravity of 1.65 Therefore, the sediment transport velocity for sand can

be studied based on the grain-size distribution of sediments

Tiêu đề	Offshore Pipeline Design, Analysis, and Methods
Trường học	Vietnam National University of Science and Technology
Chuyên ngành	Offshore Pipeline Engineering
Thể loại	Thesis
Thành phố	Hanoi

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