Piping Design Guidelines for Horizontal Drums

Written by Anup Kumar Dey in Mechanical,Piping Design Basics,Piping Interface

Drums are cylindrical vessels that are used in the process units for a variety of functions. These include intermediate liquid collection, product storage, separation of two different products of different densities, surging, reflux accumulation, and de-aeration. For the above-mentioned functions, the internals required are limited to baffles, demister pads, vortex breakers, distributor piping, and draw-off piping.

Types of drums

Drums are divided into two categories, depending on the orientation of the cylindrical axis. Thus, we have horizontal and vertical drums. Inclined drums are treated as horizontal drums in most cases.

Locating the Horizontal drums

The piping designer is should economize piping interconnections between the drum and its adjacent equipment when locating the drum. The following documents are needed to locate the drum on the plot plan.

P&ID
Process Vessel Sketch
Plot plan
Piping & Plant Layout Specification.
The drum is located on the plot plan as per the process sequence dictated by the P&ID.
Drums can be placed on standalone structures or grouped together with related equipment in an enclosed structure. Adequate space must be provided around the drum for operator movement and maintenance access.
The drum elevation is fixed by the P&ID. The same may be increased to facilitate piping and equipment layout in consultation with the Process group.
Keeping the axis of the drum perpendicular to the pipe rack minimizes the space required for locating the drum. Locate close to an access road to reduce maintenance efforts.
Underground (U/G) drums should be preferably located in open and easily accessible areas. Nothing should be located above the U/G drum as it may be required to be taken out and replaced.
Underground drums are used to collect gravity-draining liquids like slops. The elevation of the drum should be checked properly as it is supposed to be the lowest point in the collection system. The pipe slope of the underground line, starting point elevation, and the approximate length of piping should be known before the vessel elevation is cleared. The elevation can be lowered below the one specified in the P&ID if the end elevation works out to be below the one given in the P&ID.
U/G drums generally have vertical pumps and motors mounted on top. Both should be accessible from HPP for plant operation and routine maintenance.
Drums with mixers and agitators should have a minimum removal space above them equal to the length of the mixer or agitator inside the drum plus one meter.

After the drum has been located on the plot plan, the following jobs are carried out.

Drum Elevation review
Nozzle orientation
Vessel support location planning
Platform and access requirement
Support cleat location detailing
Lifting lugs and earthing lugs location planning
Finalizing Vessel Name Plate location

Drum Elevation review:

Drum elevation set by the P&ID is the minimum required elevation from the NPSH point of view. This can be increased to suit supporting arrangements.

Nozzle orientation:

The following documents are required for orienting the nozzles.

Process vessel sketch
Level co-ordination diagram
P&ID
Plant layout specification
Nozzle summary
Insulation requirements
Plot plan

General considerations for locating nozzles:

Generally, the following nozzles are present on all drums.

Product Inlet
Product Outlet
Vapour Outlet
Drain and Vent
Instrument Nozzles
Steam Out Nozzle
Access Manway

Orienting the nozzles:

While orienting these nozzles the following points are to be considered.

The product Inlet and Vapour Outlet will be on the top of the drum, as far from each other as possible for proper dis-engagement of liquid and vapor.
The product Outlet will be on the bottom and as far as possible from the Product Inlet.
Level Instrument nozzles should be as far from
the inlet as possible to avoid turbulence at the inlet end.
Pressure tapping for vapor pressure to be on the top of the drum, near the Vapour outlet.
Temperature tapping for the liquid temperature to be in the lower liquid region. It is to be ensured that sufficient space is available for the removal of the temperature element. When multiple temperature elements are required, they are best placed at the same elevation along the axis of the drum.
Steam out connection to be opposite to the access manway and vent.
The drain is to be located at the lowest point, on the bottom of the drum.
Inaccessible Instrument nozzles to be located near ladders (location of ladder and Instrument nozzles to be decided concurrently)
Access manway can be located at the following places, depending on the type of access required into the drum.
On the top of the drum.
On the cylindrical portion of the drum (radially or hillside) or at either head for side entry.
On the bottom of the drum.
- It should be verified that the davit swing area of the manhole cover does not obstruct the movement of maintenance personnel and does not hit any instruments or instrument nozzle connections. The center line of the manhole should be between 600mm to 1000mm (ideally 760mm) from the top of the service elevation of the vessel.
Special consideration is to be taken for bottom nozzles. They should be located so that they not only clear the saddle support (R/F pads should clear), but they should also clear the concrete or structural support on which the saddle support rest. A minimum of 150mm should be available between the edge of the flange and the edge of the civil support for easy maintenance.
Gooseneck nozzles should be considered when the piping layout is fixed and requires an elbow immediately at the nozzle.
In addition to the regular nozzles, vessel boots may be provided for liquid accumulation. This is provided at the bottom of the vessel. The boot should be located as per the guidelines of outlet nozzles. The boot has a draw-off nozzle at the bottom and a minimum of an instrumented nozzle for level measurement. This has to be oriented in conjunction with the upper-level nozzle (on the drum).

Nozzle standouts

Nozzles on the top of the drum should have their flange a minimum of 180mm and a maximum of 1000mm from the TOG of the access platform. Hillside nozzle standouts should be calculated so that there is no clash (hard or soft) between the insulation of the drum and the standpipe. The flange and bolts should also be outside the vessel insulation. Standouts of Nozzles on the heads and on the bottom should be calculated so that the flange and bolts are outside the vessel insulation so that the flange joint is easily accessible for maintenance.

Supporting the Drum:

Horizontal drums are supported on saddles welded to them. These are to be evenly spaced from the center of the drum. Specific requirements on spacing can be passed on to the Mechanical group. For very long drums, additional saddles may be required to prevent the sagging of the drum at the center. This will be indicated by the Mechanical department. The saddle towards the pipe rack is generally made the fixed end and the other support is made the sliding end. This is done in conjunction with piping growth calculation. Slot hole dimensions when provided by vendor drawing should be cross-checked with manual calculation to verify the actual size of the slot required. An additional 5 mm should be added to take care of minor civil dimensional variations.

Preparing the Nozzle Orientation Document:

This document should show the plan, elevation and if required, the side view of the vessel, the proposed location of saddles, and the location of nozzles. Nozzle dimensioning should be from the centerline and one tan line. Nozzle projections should be from the vessel center line. A nozzle summary table indicating the Nozzle number, service, size, rating, flange type, flange face, standout, and remarks is to be included in the drawing.

Miscellaneous Data to be included in Nozzle Orientation Document:

Lifting Lugs

Generally, drums can be lifted with two lugs welded on the top of the vessel. The preferred locations should be marked on the nozzle orientation drawing.

Earthing Lugs

Two earthing lugs, ideally one on each saddle support should be marked on the nozzle orientation drawing.

Name Plate

The nameplate should be located at a prominent location and marked on the nozzle orientation drawing. Care should be taken that the nameplate projects outside the vessel insulation.

Vessel Insulation Clips

Indicate that insulation clips/rods are required for holding the vessel insulating bands.

Platforms and Access Ladders

Platforms are required for operational access to valves, and instruments, and for maintenance. Horizontal drums are to be provided on rectangular platforms.

Calculating the TOG elevation

TOG elevation from the top of the drum = Insulation thickness + 50 mm clearance + Platform member depth (assume 200mm minimum) + 30 mm grating. Round off to the next higher multiple of 10.

Platform sizing

A platform should cover all the nozzles that need access for operations and maintenance. Ideally, a space of 750mm should be provided around 3 sides of a nozzle. This may be lowered at the discretion of the piping lead.

Also, the shape of the platform should allow side entry from the access ladder.

Platforms longer than 6 m should have two access ladders.

Access ladder

An access ladder is provided for entry to equipment platforms. It is also to be utilized for access to instrument connections that are inaccessible from the working level. The ladder should side entry type, wherever possible.

Preparing the Platform Input Document

Platform and Access ladder input is transmitted to Civil via a platform input drawing. This should clearly indicate the TOG, dimensions, and its location w.r.t. the vessel centerline and one tan line. Grating cutout requirements (indicating size, shape, and location) need to be marked on the same drawing.

Supporting Piping from Drums:

Piping should be supported from the vessel or its platform when it is difficult to construct civil support from grade or adjacent structures at the required location. Vessel support may also be taken to take advantage of lower differential thermal growth between vessel and piping, as compared to piping and civil support. A judicious selection of support locations can eliminate the requirement for springs.

Thumb rules for supporting from drums:

Small loads can be transferred directly to the platform members. These include rest, one-way stops, two ways stop, or hold-down supports and the piping layout should be done accordingly.
Large loads should be transferred to the vessel shell and the piping layout should be done such that the platform members do not interfere with these independent supports.
Piping support should not cause any hindrance to the movement of personnel.
Vessel growth should be considered to check the clash of piping support with any adjacent piping or structure.

Preparing the CPS Input Document

CPS (Civil Pipe Support) input is transmitted to Civil and Mechanical via a CPS input drawing. A sketch clearly indicating the TOS, dimensions, and the CPS location with respect to the vessel center line and one tan line needs to be drawn. A summary table indicating the CPS number, TOS, location of load w.r.t. vessel center line, stress file number, and corresponding node number from the Nozzle cleat load information chart needs to be created. The Nozzle cleat load information chart indicates the various loads acting at the support location under various conditions. It is to be attached along with the CPS input document.

What are Drilling Rigs? | Types of Drilling Rigs

Written by Anup Kumar Dey in Pipeline,Piping Design Basics,Piping Interface

Drilling rigs are massive structural equipment that is used to drill water wells, oil wells, or natural gas extraction wells. By rotating a bit, a hole is drilled using a downward force.

Types of Reservoir

Sandstone
Limestone

Main Trapping Mechanism

Anticline
Fault
Stratigraphic

Types of Drilling Rigs

Drilling Rigs are classified as follows

Land Rigs
Submersible Rigs
Jack-up Rigs
Platform Rigs
Semi-submersible Rigs
Drill Ship Rigs

Based on the configuration of the drilling rigs, they are grouped into Light, Medium, Heavy and Ultraheavy groups. The capabilities of such drilling rigs are tabulated below:

Duty	Depth
	Feet	Meters
Light	3000 – 5000	1000 – 1500
Medium	4000 – 10,000	1200 – 3000
Heavy	12,000 – 16,000	3500 – 5000
Ultraheavy	18,000 – 25,000	5500 – 7500

Table: Drilling Rig Configurations

Land Drilling Rigs

The features of Land drilling rigs are

They typically come in light, medium, or heavy configuration
Is moved using heavy trucks and cranes
Small rigs may only drill to a few thousand feet.
But larger ones are capable of 12,000 and more

Submersible Drilling Rigs

The features of Submersible Drilling Rigs are

Tend to drill in fairly shallow water. They flood the legs with water and submerge them.
Some of the rigs are above water, and crews drill from that location.
Swamp type, river, and inland bay areas
Typical water depths are 20 feet

Jack-up Drilling Rigs

The features of Jack-up Drilling Rigs are

Have lattice legs that can be hoisted and lowered at will.
They are hoisted and the rig is either towed or transported by ship.
When in location, the legs are lowered to the sea bed.
Jack-up rigs can drill in water depths up to 400ft

Platform Drilling Rigs

The features of Platform Drilling Rigs are

Are immobile once built.
However, they drill several wells from one location.
They can be tender assisted.
Three types of Platform are:
1-Steel Jacket, 2- Caisson Type 3- Concrete Gravity

Semi-submersible Drilling Rigs

The features of semi-submersible drilling rigs are

Has hollow legs and pontoons. Like the submersible, the legs are also flooded
However, anchors and/or Thrusters and Positioners keep the rig in position,
When thrusters are used, it is called Dynamic Positioning (computer controlled),

Drill Ship

Are self-propelled, floating offshore drill units
A template that has holes drilled though it is fitted to the sea bed

Rig Systems

The Power System
The Rotating System
The Hoisting System
The Circulating System
The Blowouts Prevention System

Power System

Subdivided into two parts

Power Generation
Power Transmission
- Electrical Transmission
- Mechanical Transmission

Hoisting System

The supporting structure
The hoisting equipment

Circulating System

Drilling Fluid

Transports cutting out of the hole
Supports well-bore wall
Cools and lubricates bit and drill stem

Fluid Composition

Water-based drilling fluid
Oil-based mud
Air or gas-based drilling fluids

Blowouts Prevention System

The BOP system has two functions

To seal the wellbore on a kick
To maintain sufficient back pressure

BOP used in

Land
Submersible
Jack-up
Platform

Sub Sea BOP used in

Semi-submersible
Drill Ship.

Casing Design

Hydrostatic Pressure- Hydrostatic Pressure is defined as the pressure exerted by a column of fluid this pressure is a function of average fluid density and the vertical height or depth of the fluid column.

Mathematically it is expressed as:

HP=g. ρf.D

HP = Hydrostatic pressure. (psi),
g = Gravitational acceleration,
ρf = Average fluid density. (ppg),
D = True vertical depth. (ft)

Pore Pressure- Pore Pressure is defined as the pressure acting on the fluids in the pore spaces of the rock.

Normal Pore Pressure: Normal pore pressure is equal to the hydrostatic pressure
Abnormal Pore Pressure: It is defined as any pore pressure that is greater than the hydrostatic pressure
Subnormal Pore Pressure: It is defined as any pore pressure that is less than the corresponding pore fluid hydrostatic pressure at a given depth
Overburden Pressure: Overburden Pressure is defined as the pressure exerted by the total weight of overlying formations above the point of interest,
Fracture Gradient: It is defined as the pressure at which formation breakdown occurs

Functions of Casing

Prevent cave-in or washout of the hole
Prevent contamination between zones
Exclude water from producing formations
Confine production to the wellbore
Provide a means for controlling well pressure
Provide a path for produced fluids
Permit installation of artificial lift equipment

Casing Design Principles

Collapse Pressure- This pressure originates from the column of mud used to drill the hole and acts on the outside of the empty casing, Since the hydrostatic pressure of a column of mud increases with depth collapse pressure is highest at the bottom and zero at the top.

Collapse (C):

C = mud density x depth x acceleration due to gravity,

C = ρgh,

C = 0.052 ρ h

Burst: The burst criterion is normally based on the maximum formation pressure resulting from a kick during the drilling of the next hole section.

Therefore, the burst pressure is highest at the top and lowest at the casing shoe where internal pressure is resisted by the external pressure originating from fluids outside the casing.
Burst pressure at the surface (B1) = Pf – G x TD, Calculate the internal pressure (Pi) at the shoe using the maximum formation pressure at the next hole TD, assuming the hole is full of gas:

Pi = Pf – G (TD – CSD)

Pe = 0.465 x CSD,

Burst pressure at shoe (B2) = Pi – Pe

B2 = (Pf – G) x (TD – CSD) – 0.465 x CSD.

Tension: Most of the axial tension arises from the weight of the casing itself, Other tension loadings can arise due to: Bending, Drag, Shock loading, and during pressure testing of the casing.

Calculate the weight of the casing in the air (positive value) using true vertical depth,

Casing air weight = casing weight (lb/ft) * hole depth (TVD),

Calculate buoyancy for (negative value),

BF = Pe (Ae – Ai) for the open-ended casing,

BF = Pe Ae – Pi Ai for closed casing

Offshore Pipeline Design Guidelines

Written by Anup Kumar Dey in Pipeline,Piping Design Basics,Piping Interface

This presentation will explain the following points in brief

Design criteria and considerations for pipe wall thickness
Pipeline stability calculations
Cathodic protection and anode sizing calculations.
Pipeline laying analysis
Pipeline Construction methods and procedure
Repair procedure

Categorization of Fluids

Fluids to be transported by the pipeline system shall be categorized according to their hazard potential.

Category	Description
A	Non-Flammable water-based fluids
B	Flammable and/or toxic substances which are liquids at ambient temperature and atmospheric pressure conditions.
C	Non-Flammable substances which are non-toxic gases at ambient temperature and atmospheric pressure conditions.
D	Non-toxic single-phase natural gas
E	Flammable and/or toxic fluids are gases at ambient temperature and atmospheric pressure conditions.

Pipeline Location Classes

The pipeline system shall be classified into location classes as defined in the table.

Location	Definition
1	The area where no frequent human activity is anticipated along the pipeline route.
2	The part of the pipeline is in the near platform (manned) area or in areas with frequent human activity. The extent of location class 2 should be based on appropriate risk analyses. If no such analyses are performed a minimum distance of 500 m shall be adopted.

SUBSEA PIPELINE ZONES	LOCATION	REASON
LANDFALL AREA	2	FOR FREQUENT HUMAN ACTIVITY ALONG THE PIPELINE ROUTE. NOTE: SHIPS ARE TREATED UNDER HUMAN ACTIVITY
500 m NEAR SHORE ADJACENT TO LANDFALLS	2
SHIPPING CHANNEL	2
ANCHORING AREA	2
REST ZONE	1	NO FREQUENT HUMAN ACTIVITY IS ANTICIPATED.

Safety Classes

Pipeline design shall be based on potential failure consequences.

Safety Class	Definition
Low	Low risk of human injury and minor environmental and economic consequences. (Installation phase)
Normal	Considerable risk of human injury, significant environmental pollution or very high economic and political consequences. (Operation outside platform area)
High	High risk of human injury significant environmental pollution or very high economic and political consequences. (Operation in location class 2).

SUBSEA PIPELINE ZONES	LOCATION	SAFETY CLASS (FLUID CATEGORY E)
CONSTRUCTION PHASE	OPERATION PHASE
LANDFALL AREA	2	LOW	HIGH
500 m NEARSHORE ADJACENT TO LANDFALL	2	LOW	HIGH
SHIPPING CHANNEL	2	LOW	HIGH
ANCHORING AREA	2	LOW	HIGH
REST ZONE	1	LOW	NORMAL

Note: construction phase means up-to pre-commissioning

Minimum and Maximum Water Depths

The maximum and minimum water depths for various subsea pipeline zones shall be listed as below:

SUBSEA PIPELINE ZONES	LOCATION	WATER DEPTHS RANGE (m)
MAXIMUM	*MINIMUM ()**
LANDFALL AREA	2
500 m NEARSHORE ADJACENT TO LANDFALLS	2
SHIPPING CHANNEL	2
ANCHORING AREA	2
REST ZONE	1

Installation of Pipeline

Pipeline route survey
Marine operations
Pipeline installation
Tie-in operations
As-laid survey
Span rectification and pipeline protection
Installation of protective and anchoring structures
Installation of risers/ platforms/ buoys
As-built survey
Final testing and preparation for operation

Operation

Organization and management
Start-up and shutdown
Operational limitations
Maintenance
Corrosion control, inspection, and monitoring
General inspection
Special activities

Abandonment

Environment and especially pollution
Obstruction for ship traffic
Obstruction for fishing activities and
Corrosion impact on other structures

Design Principles-System Integrity

Fulfill the specified transport capacity
Fulfill the defined safety objective and have required resistance against loads during planned operational conditions and
Have sufficient safety margin against accidental loads or unplanned operational conditions

Monitoring/Inspection during operation

Parameters that could violate the integrity of a pipeline system shall be monitored and evaluated with a frequency that enables remedial actions to be carried out before the system is damaged.
Instrumentation of the pipeline system.
The pressure in a pipeline system shall not exceed the design pressure during normal steady-state operation.

Pressure Control System

A pressure control system shall be used to prevent the internal pressure at any point in the pipeline system from rising to an excessive level.
The pressure control system comprises the pressure regulating system, pressure safety system and associated instrumentation and alarm system.

Pipeline Route-Route Survey

A survey shall be carried out along the planned pipeline route to provide sufficient data for design and installation-related activities.
The survey corridor with sufficient width.
To identify possible conflicts with existing and planned installations and possible wrecks and obstructions.
All topographical features which may influence the stability and installation of the pipeline – unstable slopes, sand waves, deep valleys, large boulders, etc.

Pipeline Route- Seabed properties

Geotechnical properties necessary for evaluating the effect of relevant loading conditions shall be determined for the seabed deposits
Soil parameters
Problems with respect to excavation and burial operations
Problems with respect to the pipeline crossing
Problems with the settlement of the pipeline system and /or the protection
Possibilities of mudslides or liquefaction as the result of repeated loading and
Implications for external corrosion

Environmental Conditions

WIND TIDE WAVES INTERNAL WAVES AND OTHER EFFECTS DUE TO DIFFERENCES IN WATER DENSITY

CURRENT ICE EARTHQUAKE SOIL CONDITIONS TEMPERATURE MARINE GROWTH

Determination of pipe wall thickness for subsea pipeline section following failure modes to be considered:

Failure Mode

PRESSURE CONTAINMENTS
SYSTEM COLLAPSE
PROPAGATION BUCKLING

Governing Factors

The pressure containment (bursting) limit state is not the governing case in determining the pipe wall thickness
Both pipeline installation and propagation buckling criteria are important in governing the pipe wall thickness
Buckle arrestor if necessary.

Governing Codes

The pipeline wall thickness for the subsea pipeline section is designed in accordance with the guidance provided in DNV OS – F101 submarine pipeline systems

Pipeline Diameter

The inside diameter is generally taken as constant along the entire pipeline length in order to facilitate the pigging operation.

Steel Grade

The subsea pipeline steel (of C-Mn)grade is selected as API-5L X65 considering the probability of accidental events (e.g. from earthquakes, ships, unauthorized traveling, etc.).

DESIGN PRESSURE
DESIGN TEMPERATURE RANGE
PRODUCT DENSITY

CORROSION ALLOWANCE:

For gas composition (no water present), it is expected that there will be no internal corrosion. Thus no internal corrosion allowance may be taken.
For fluid composition (water present), it is expected that there will be internal corrosion. Thus internal corrosion allowance may be taken.

Design Philosophy

The required pipe wall thickness is established considering the following:

Pressure containment (bursting) limits the state

For operation phase
For the system pressure test

Local buckling limit state

External pressure ) collapse
Propagation buckling

Pressure Containment (BURSTING)

The calculation steps are listed below…

Step 1: Determine the thickness requirement at the landfall area
step 2: verify the above thickness from the system test
step 3: verify the above thickness from operation condition at a maximum Water depth
step 4: verify the above thickness for system test pressure at a maximum water depth

Change the thickness value, if necessary to satisfy the checks and conclude the minimum thickness requirement from pressure containment (bursting).

System Collapse and Propagation Buckling

The calculation steps are listed below…

Step 1: Verify the above-determined thickness for system collapse in maximum water depth condition
step 2: change thickness, if necessary to satisfy the system collapse check
step 3: verify the above-determined thickness for propagation buckling in maximum water depth condition
step 4: change thickness, if necessary to satisfy the propagation buckling check.

Conclude the pipe wall thickness requirement from system collapse and propagation buckling criteria.

PRESSURE CONTAINMENT (BURSTING)-AT ABOVE-WATER LOCATIONS:

For landfall locations that are of safety class “high”, the pipeline thickness requirement is calculated for operating condition
If this thickness is more than the minimum requirement of 12 mm, this thickness is retained for further checks.
To complete the installation phase of the subsea pipeline system, a pressure test would be performed. The pipeline is filled with water during the pressure test. Find out whether it is acceptable or not.

STABILITY CALCULATIONS FOR THE SUBSEA PIPELINE – CONCRETE THICKNESS DESIGN:

BASIC CONSIDERATIONS:

The water depth variation along the subsea pipeline route is considered.
In the shipping channel and in the ship anchoring area, the pipeline must be in a trench with a cover of 1.3 D, D being the overall coated pipe diameter.
Postlay trenching may be considered if soil condition permits.
Environmental data (wave and current).
Current is considered to always act perpendicular to the pipeline.
Most conservative wave with its direction/ approach with respect to the pipeline axis is considered.
Wave refraction is neglected.
Concrete thickness shall be designed in multiple of 5 mm (e.g. 50 mm, 55 mm, 60 mm etc. and shall be optimised to reduce strain concentration at field joints during pipelaying.

Environmental conditions for different pipe burial conditions:-

When pipeline section is designed as	Wave and current return period conditions to be considered
1 year	10 year	100 year
Exposed section	–	–	Yes
Postlay trenched section	Yes (Exposed)	Yes (in trench)	Yes (in trench)
Prelay trenched section and mechanically backfilled following pipeline installation	Yes (in trench)	Yes (in trench)	–

Design Methodology:

Step – 1:

First check whether the steel pipe is having a negative buoyancy force or not (in absence of wave and current). If not, find out the minimum concrete thickness to make the pipeline negatively buoyant.

Step – 2:

Consider exposed pipeline on sea bed and carry out stability assessment. For the purpose consider the deeper part of the pipeline route.
Find out the minimum required concrete thickness for various water depth upto maximum water depth. Decide on the exposed pipeline section length (with its minimum and maximum water depth) and an uniform concrete thickness (if possible) for this section.

Step – 3:

Find the concrete thickness requirement (for the pipe exposed installation period – 1 year return period conditions for wave and current) for various water depths shallower than the above determined minimum water depth of the exposed pipe section.
Consider postlay trenching for this zone and check the pipe stability (with the above designed concrete thickness) under 10 years and 100 years return period environmental conditions (to check pipeline stability for backfill with excavated soil and naturally backfilled condition, respectively) to conclude the concrete thickness requirement for this postlay trench zone. Minimum and maximum water depths are to be noted for this zone.
The pipeline in the rest water depths shallower than the above minimum water depth limit shall be in a prelay trench which will be mechanically backfilled following pipeline installation.

Step – 4:

Check sample pipeline stability in the prelay trench zone for the installation period (1 year and 10 year return period conditions for wave and current) and decide on the concrete thickness requirement for this zone.

Step – 5:

Check vertically stability for the pipeline (sinking in case of exposed pipe section and sinking as well as floatation in case of trenched and backfilled pipe section).

Step – 6:

Summarise the above results to highlight the concrete thickness design along the pipeline route, with the trenching (prelay and postlay) requirement as envisaged (from pipeline protection from ship hazards).

DESIGN DATA AND BASIS: LINE PIPE CHARACTERISTICS:

Pipe characteristics
Anti corrosion coating
Field joint coating
Concrete coating
Pipe contents
- During installation phase pipeline is air filled.
- During operation phase pipeline is filled with product

ENVIORNMENTAL DATA AND HYDRO DYNAMIC LOADS:

The pipeline on bottom stability assessment is based on a given return period of near-bottom environmental loads acting on the pipe. These hydrodynamic loads are defined as flow-induced loads caused by the relative motion between the pipe and the surrounding water. Most critical combination of near bottom wave induced water particle velocity (due to wave) and near-bottom current is thus considered.
For waves, the angle of attack with respect to the pipe axis is considered to evaluate the water particle velocity and acceleration normal to the pipe axis. Current are considered to be always to be acting perpendicular to the pipeline.

DESIGN DATA AND BASIS: WATER DEPTHS:

Water depth variation along subsea pipeline route is considered.

DESIGN DATA AND BASIS: ARTIFITIAL EMBEDMENT:

It is well known that the pipeline in a trench (prelay or postlay with backfilling) facilitate the lateral stability of a pipeline during its life time.
In order to ensure lateral stability of the pipe with a reasonable concrete thickness, artificial embedment may be emphasized. In the near shore and in areas having the probability of ship hazards.

DESIGN DATA AND BASIS: SOIL FRICTION:

The lateral soil friction factor for exposed pipe section is taken as 0.7 corresponding to a sandy soil sea bed.
For the postlay trench case, the lateral soil friction factor is increased to 2.144 using the slope of the trench as 30 degree. For prelay trench case (I.e. flat bottom surface) no change in soil friction is considered.

DESIGN DATA AND BASIS: CURRENT DATA:

Current velocity at the near bottom (1 meter above sea bed) shall be considered.
1 year, 10 year and 100 year return period extreme wave characteristics are selected on the basis of most critical wave case on the pipeline.

DESIGN DATA AND BASIS: Hydrodynamic force coefficients-

In order to calculate the hydrodynamic loads acting on the pipeline, the following dynamic force coefficients to be considered in accordance with following-

Pipeline case	Exposed pipe section on the sea bed	Prelay and postlay trench section with cover= 1.3XD, D being coated pipe diameter.
Drag coefficient	0.7	0.28
Lift coefficient	0.9	0.36
Inertia coefficient	3.29	1.81

DESIGN DATA AND BASIS: VERTICAL STABILITY-

It is necessary to check the following:

Sinking check for exposed pipeline section (water filled condition)
Sinking and floatation checks for trenched and backfilled pipeline sections (for sinking pipe water filled condition and for floatation pipe air filled condition)

Online Video Courses related to Pipeline Engineering

If you wish to explore more about pipeline engineering, you can opt for the following video courses

Slug Flow Analysis Using Dynamic Spectrum Method in Caesar II

Written by Anup Kumar Dey in Caesar II,Piping Stress Analysis,Piping Stress Basics

The basics of slug flow, Calculation of Slug forces, and static analysis methodology in Caesar II are provided in my last article titled “Static Analysis of Slug Flow”. Click here to read the same. In this article, We will explain the methods for performing the slug flow analysis using the Dynamic Spectrum Method of Caesar II Software.

Reason for Dynamic Slug Flow Analysis of Piping System?

The system responses are very much different with respect to dynamic slug loads as compared to a static load of the same magnitude. As static load is applied slowly, the piping system gets enough time to internally distribute the loads and react, resolving the forces and moments and keeping the system in equilibrium. Hence, the pipe movement is not visible.

On the other hand, a dynamic slug load quickly varies with respect to time and hence the piping system does not get sufficient time to distribute and resolve the forces. This results in an unbalanced slug force that leads to pipe movement. So it’s always preferable to perform dynamic analysis when dynamic loads are involved to get real analysis results.

Dynamic Slug Flow Module of Caesar II

For performing dynamic slug flow analysis, Caesar II software provides a very nice module, dynamic analysis module where we have to simply provide the input parameters to get the output result. In the following paragraphs, we will learn the steps for performing Dynamic Slug Flow using Water Hammer/ Slug Flow (Spectrum) method.

Before you start the dynamic slug flow analysis you have to perform a conventional static analysis of the system (without using any slug force) and qualify the system from all stress criteria (Thermal, Sustained, Occasional, as applicable).

To open the dynamic module in Caesar II click on the dynamic analysis button as shown in Fig.1.

Opening Dynamic Module — **Fig. 1: Opening the Dynamic Module in Caesar II**

When you click on the dynamic analysis button following window (Fig.2) will open. Select Slug Flow (Spectrum) from the drop-down menu. The window will be filled with some pre-existing data. For clarity simply select all those and delete them. Now we have to provide inputs for analysis.

**Fig. 2: Selecting Slug Flow Module in Caesar II**

During dynamic slug flow analysis, our first input will be the generation of a response spectrum profile. Slug load is one type of impulse load. So the magnitude of the load varies from zero to some maximum value, remains constant for a time, and then reduces to zero again. The force profile can be represented by a curve as shown in Fig. 3.

Fig. 3: Graphical Representation of Slug Force Profile

So from the above profile, it is clear that in addition to the slug force (Refer to Static method of Slug Flow using Caesar II for calculation of slug force), we need to calculate two additional parameters, a) Slug Duration and b) Slug Periodicity.

Slug Duration

Slug duration is defined as the time required for the slug to cross the elbow. Mathematically it can be denoted as, Slug Duration=Length of Liquid Slug/Velocity of Flow.

Slug Periodicity

Slug Periodicity can be defined as the time interval for two consecutive slugs hitting the same elbow. So mathematically it can be denoted as Slug Periodicity = (Length of Liquid Slug + Length of Gas Slug)/Velocity of Flow.

Generating Spectrum Profile for Slug Flow

Let’s assume that the calculated slug duration is 8 milliseconds and periodicity is 400 milliseconds as shown in Fig. 3. We will use these data for the generation of spectrum profiles.

Now Refer to Fig. 4 and input the data as mentioned below:

Fig.4: Generation of Spectrum Profile for Slug Flow Analysis

When you click on Enter Pulse data it will open the window where we have to enter the data for spectrum profile generation. From the above curve at time 0 the force is 2120 N the same force will be active for the next 8 milliseconds till the slug crosses the elbow. Then at time, 8.1 millisecond forces will be reduced to zero. And the same zero force will be there till 400 milliseconds. Then the next cycle will start. i.e., at time 400.1 milliseconds, the force will be again 2120 N. That way enter data for at least two cycles as shown in Fig. 5:

Fig.5: Typical Spectrum Profile for Slug Flow Analysis

Clicking the Save / Continue button will convert the time history into its equivalent force response spectrum in terms of Dynamic Load Factor versus Frequency and the screen “Spectrum Table Values “as shown in Fig. 5 will appear.

Be sure to specify a unique spectrum name, as this processor will overwrite any existing files of the same name.

By clicking OK, the processor will load the appropriate data in the Spectrum Definitions tab in Dynamic Input and move the data to the Dynamic Input.

Once the spectrum profile is generated click on the force sets button and enter the slug force with the proper direction in the fields as shown in Fig. 6:

**Fig.6: Entering slug forces for dynamic slug flow analysis.**

Click on the + button to add more rows and the – buttons to delete rows.
In the force set field, input a numeric ID which will be used to construct dynamic load cases.

Creating Dynamic Slug Flow Load Cases for Analysis

After that, click on the Spectrum load cases menu and create the required load cases for dynamic analysis. You have to specify at least two load cases as shown.

Operating + Dynamic for nozzle and support load checking.
Sustained + Dynamic for stress checking.

Refer to Fig. 7 for load case preparation

**Fig. 7: Load Case preparation for dynamic slug flow analysis**

Finally, click on the control parameters button and select the load case for which you want to perform the analysis. Normally operating load case is selected (Refer to Fig. 8) for dynamic analysis. Keep all other parameters as it is. Now click on batch run to obtain the analysis results. Fig 9 shows typical analysis results.

**Fig.8: Selecting the load case for slug flow analysis**

Output Results from Dynamic Slug Flow Analysis

Typical Output Reports — **Fig. 9: Typical Dynamic Slug Flow Output Reports**

Fig. 9 shows a typical output screen for dynamic slug flow analysis in Caesar II.
The highlighted node 10 is for the nozzle.
All support and nozzle loads are to be checked.
Stresses are to be kept below code allowable values.
The highlighted direction sign will show other load case combinations.

Some Important Points to Consider

Piping vibration due to any two-phase flow can be reduced/arrested by proper support of the piping system. Normally following supports are used:

HOLD DOWN SUPPORTS WITH 0 GAP
GUIDE SUPPORTS WITH 0 GAP
AXIAL STOPS WITH 0 GAP

Whenever modifying any support perform static analysis and keep the system stresses within the allowable limit.

Sometimes vibration-absorbing material (like PTFE) is used to reduce the transfer of vibration to connected systems.
It is preferred to keep the natural frequency of the piping system above 4 Hz for Vibration-prone lines.
The formation of Slug Flow can be reduced by
- By reducing line sizes to a minimum permitted by available pressure differentials.
- By using a low-point effluent drain or bypass.
- By arranging the pipe configurations to protect against slug flow. E.g. in a pocketed line where liquid can collect, slug flow might develop. Hence pocket is to be avoided.
- By Installing a Slug Catcher

Online Course on Dynamic Slug Flow Analysis

If you still have doubts, then the following online course is just perfect for you:

Slug Flow Analysis in Caesar II (Both Static and Dynamic)

Some handpicked useful resources for you…

Static Analysis of Slug flow
How to Model Slug Flow Loads
An Introduction to Pressure Surge Analysis
Understanding Centrifugal Compressor Surge and Control
Load Cases for Stress Analysis of a Critical Piping System Using Caesar II
Water Hammer Basics in Pumps for beginners
Pipe Stress Analysis from Water Hammer Loads

What is Fluid Flow?

Written by Anup Kumar Dey in Process

Fluid Flow is generally measured inferentially by measuring velocity through a known area. With this indirect method, the flow measurement is the volume flow rate ”Q” stated in its simplest terms.

Volume flow rate (Q)

It is expressed as a volume delivered per unit time and typical units are gallons/min, m³/hr, and ft³/hr.
Q = A * V

Where: A is the cross-sectional area of the pipe & V is the fluid velocity.

Mass or weight flow rate

Expressed as mass or weight flowing per unit time. Typical units are kg/hr, Ib/hr.

This is related to the volume flow rate by F = p * Q

where

F = Mass or Weight flow rate.
p = mass density or weight density.
Q = volume flow rate

Factors affecting Flow in Pipes

Velocity (V) of the fluid.
The friction of the fluid in contact with the pipe.
Viscosity (µ) of the fluid.
The density of the fluid.

The most important flow factors can be correlated together into a dimensionless parameter called the Reynolds number. It describes the flow for all velocities, viscosities, and pipeline sizes.

In general, it defines the ratio of velocity forces driving the fluid to the viscous forces restraining the fluid, or:

R_D = VDρ/µ

D=Diameter ;

Fluid Flow in Pipes

At very low velocities or high viscosities, R_D (Reynolds Number) is low and the fluid flows in smooth layers with the highest velocity at the center of the pipe and low velocities at the pipe wall where the viscous forces restrain it. This type of flow is called laminar flow and is represented by Reynolds numbers below 2,000. One significant characteristic of laminar flow is the parabolic shape of its velocity profile

At higher velocities or low viscosities, the flow breaks up into turbulent eddies where the majority of flow through the pipe has the same average velocity. In the “turbulent” flow the fluid viscosity is less significant and the velocity profile takes on a much more uniform shape.

Turbulent flow is represented by Reynolds numbers above 4,000. Between Reynolds number values of 2,000 and 4,000, the flow is said to be in transition.

Measurement of Fluid Flow inside a Pipe

The type of device used often depends on the nature of the fluid and the process conditions under which it is measured.

Flow is usually measured indirectly by first measuring a differential pressure or a fluid velocity. This measurement is then related to the volume rate electronically.

Flow meters can be grouped into the following generic types:

Head Type Flow Meters– Orifice Plates, Venturi, Flow Nozzles, Pitot Tubes, etc.
Target Flow Meters.
Positive Displacement Type Flow Meters such as Nutating Disc, Rotating Valve, Oval Gear, Oscillating Piston, Roots (Rotating Lobes), Rotating Impeller, etc.
Velocity Type Flow Meters such as Turbine Meters, Electromagnetic Flow Meters, Vortex Flow Meters, Ultrasonic Flow Meters, etc.
Mass Flow Meters such as Thermal Mass Flow Meters, Coriolis Mass Flow Meters, etc

All the above flow meter types will be explained in my future articles.

Flow Fundamentals

Accurate Measurement Requires the Right Meter Choice for the Application

Newtonian fluid

A Newtonian fluid is defined as a fluid that, when acted upon by applied shearing stress, has a velocity gradient that is solely proportional to the applied stress. Petroleum products and most mixtures of particles in petroleum products are Newtonian fluids.

The accuracy of flow meters is based on the steady flow of a homogenous, single-phase Newtonian fluid, and for turbine and ultrasonic meters a defined velocity profile does not alter the coefficient in long, straight runs of pipe.

Raynolds Number

A dimensionless parameter expressing the ratio between the inertia (driving) and viscous (retarding) forces.

It is given by the formulas:

Re = 2214 x BPH / (D x n)

Re = 351 x M³/hr / (D x n)

where: The flow rate is in BPH barrels/hour (or M3/hr); D is the diameter of the meter in inches and n is the kinematic viscosity of the fluid.

Fig. 2 below shows the curves for flow profile vs Reynolds number and Flow profile vs Performance

Fig. 2: Flow profile

Figure 3 shows various curves/profiles related to Fluid Flow.

**Fig. 3: Fluid flow and velocity profiles.**

What is Restrained and Unrestrained Pipes: Part 2

Written by Alex Matveev in Caesar II,Piping Stress Analysis,Piping Stress Basics,Start-Prof

Start-Prof is a part of PASS software suite for piping stress analysis, hydraulics analysis, boiler & pressure vessel, heat exchanger, column, tank design & stress analysis is available worldwide since 2018.

Continued from Part 1

Restrained and Unrestrained Zones in the Buried Pipelines

Buried gas and oil pipelines usually are very long and have a small temperature difference. In this case all three types of pipe condition occur: unrestrained, totally restrained and partially restrained.

Let’s assume that soil model is ideal plastic:

In this case the axial stress and axial displacement diagram along the pipeline will be as follows:

Unrestrained, Partially Restrained, and Unrestrained Zones in Buried Pipeline with an Anchor on the Left End and Free Right End With Ideal Plastic Soil Model

As we see unrestrained zone on the right end of the pipe is a very small. The most length of pipeline consists of totally restrained and partially restrained zones.

Anchor load in restrained zone will be:

Axial force at restrained zone is:

Stress at restrained zone is:

Axial force at unrestrained zone is:

Stress at unrestrained zone is:

Balance equation:

Therefore virtual anchor length is

Stress function in unrestrained zone is:

Displacement function in unrestrained zone is:

Axial displacement at restrained zone should be zero. Therefore:

Axial displacement at the right end of the pipe will be

For more complex and more realistic Elastic-plastic soil model that is used in PASS/Start-Prof pipe stress analysis software the zero displacement (totally restrained) zones is absent:

Let’s assume that restrained zone begins when axial displacement is very small, for example 1% of maximum displacement. Bypassing complex calculations the sliding zone length that is used in PASS/Start-Prof software is:

Virtual anchor length using FEM procedure can be calculated in PASS/Start-Prof Software using Start-Elements module:

Start-Elements Procedure for Virtial Anchor Length Calculation

Strength Criteria in ASME B31.4 and B31.8 Codes

In real design practice the determination of the restrained zones is very time consuming. For example on the screenshot below the restrained zones of a very long gas pipeline are shown.

That’s why we decided to create universal strength criteria that automatically meets the B31.4 and B31.8 code strength requirements, but can be used for any type of piping. The problem is that ASME B31.4-2016 and B31.8-2016 has unclear requirements for stress analysis.

ASME B31.4 code, paragraph 402.6.2 requires longitudinal stress in unrestrained pipe to be less than 0.75Sy for sustained loads and 0.8Sy for occasional loads.

This requirement can be extended for all pipe conditions, no matter restrained or unrestrained, but for primary loads. Longitudinal stress in any type of piping from sustained primary loads (weight and pressure) should be less than 0.75Sy:

M and Fa should be calculated by software including Bourdon effect.

ASME B31.4 code, paragraph 402.6.1 requires longitudinal stress in restrained pipes to be less than 0.9Sy, the equivalent stress should be less than 0.9Sy

This requirement can also be extended for all pipe conditions, but for primary and secondary loads acting simultaneously (weight, pressure, and thermal expansion).

M and Fa should also be calculated by software including Bourdon effect. In this case axial pressure stress will be correct for both restrained and unrestrained zones.

The expansion stress should be checked for both restrained and unrestrained pipes.

The same way ASME B31.8 strength criteria can be improved.

The summary of suggested strength criteria for ASME B31.4 and B31.8 shown in the following tables.

Table 1. Original ASME B31.4-2016 Strength Criteria

Start Smart Check ASME B31.4-2016 Improved Strength Criteria

Table 3. Original ASME B31.8-2016 Strength Criteria

Table 4. Start Smart Check ASME B31.8-2016 Improved Strength Criteria

We already implemented the improved ASME B31.4 and B31.8 strength criteria into PASS/Start-Prof software and call it “Start Smart Check”. Every user can select this option and forget about manual selection of restrained and unrestrained pipes in stress analysis software.

Selection of Start Smart Check Option in PASS/Start-Prof

Also we added “manual” and “Autodetect” options. Using “manual” option user should select restrained or unrestrained option for each pipe. If “Autodetect” option is selected, Start-Prof automatically use equations for restrained pipe if following condition is truth:

Manual option is not recommended because it seriously slows down the design process. Autodetect option is not recommended because the strength criteria will be sometimes too conservative and sometimes less conservative for partially restrained pipes.

We recommend users to select “Start Smart Check” option by default because the similar criteria are already used successfully in Start-Prof (GOST codes) for buried pipelines for many years and proved their reliability. You can just draw pipeline and run analysis. There’s no need to divide it into restrained and unrestrained.

Related video about buried piping analysis:

More than 100 Chinese companies choose START-PROF for buried district heating networks analysis with CJJ/T 81-2013 code is used instead of ASME B31.4. CJJ/T 81-2013 is adopted version of GOST 55596-2013 code. This code is free from described above problems, and ideas of ASME B31.4 and B31.8 code improvment in this article was taken from GOST 55596-2013 code.

Example: District heating buried piping network in Universal Studios Park in Beijing calculated using PASS/START-PROF

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