pipelin note

8/3/2019 Pipelin Note

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4.5. PIPELINES

4.5.1 Introduction

Pipelines are the most common means of transporting oil or gas.

A pipeline is like any other flowline. The main differences are that pipelines are long andcontinuously welded, they have a minimum number of curves, they have no sharp bends, and

they are most often either buried or otherwise inaccessible due to their location over the majorityof their length.

These differences mean that small sections of pipeline are not easily removed for maintenance

and consequently great care is taken to prevent problems arising in the first place. A pipeline isextremely expensive to lay, and in the case of offshore pipelines, costs in the order of several

million pounds per subsea mile have been encountered.

Maintenance on pipelines is also expensive but this expenditure is necessary since, regardless of

the expense, pipelines frequently form the most efficient and cost-effective method of transporting the quantifies of oil or gas produced. Pipeline sharing agreements may result in theflow from a number of oil fields being transported through a single pipeline. A problem in a

pipeline of this type can mean the shut-down of all of these fields with a resulting operating lossof several million pounds per day.

This situation can be further aggravated for gas production to gas consumer companies where the

producing company can not only lose operating revenue but can incur fines for failing to fulfillcontractual obligations.

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4.5.2 Pipeline Design

4.5.2.1 General

When designing a pipeline, the engineer considers the following factors:

The physical and chemical properties of the fluid, or to pumped through the pipeline;

The maximum volume of fluid that will be pumped through the pipeline at any time during thelife of current and future developments likely to be served by the pipeline.

The nature of the environment through which the pipeline is going to traverse.

The required delivery pressure.

More specifically the engineer considers

Pipe diameter required. (The larger the diameter of the pipeline, the more fluid can be moved

through it, assuming other variables such as pump capacity are fixed.)



Pipe length. (The greater the length of a segment of pipeline, the greater the total pressure

drop. Pressure drop can be the same per unit of length for a given size and type of pipe but total pressure drop increases with length.)

Specific gravity and density of the fluid to be transported, (The specific gravity and density of the transported fluid will affect the potential amount of mass flow available.)

Compressibility. (Because most liquids are only slightly compressible, this term is not usuallysignificant in calculating liquids pipeline capacity at normal operating conditions. In gas and gas

liquids (mixtures of methane, ethane, propane, butane, etc, transported as a liquid) pipelinedesign, however, it is necessary to include a term in many design calculations to account for the

fact that gases deviate from laws describing ideal gas behaviour under conditions other thanstandard or base conditions. This term, supercompressibility factor, is very significant at high

temperatures and pressures. If in the pipeline, pressure is likely to be in the order of 1000 to 2000 psig then this term must be included.)

Operating temperatures and ambient temperatures: (Temperature affects pipeline capacity

both directly and indirectly. In natural gas pipelines, the lower the operating temperature, thegreater the capacity, assuming all other variables are fixed.

Operating temperature also can affect other terms in equations used to calculate the capacity of

both liquids and natural gas pipelines. Viscosity, for example, varies with temperature.Designing a pipeline for heavy (viscous) crude is one case in which it is necessary to know

operating temperaturesaccurately to calculate pipeline capacity. The possibility of water freezing and of hydrate

formation in gas pipelines are other temperature considerations.

Viscosity: (The property of a fluid that resists flow or relative motion between adjacent parts of the fluid is viscosity. It is an important term in calculating line size and horsepower requirement

when designing liquid pipelines).

Pour Point: (The lowest temperature at which an oil will pour, or flow, when cooled under specific test conditions is the pour point. oils can be pumped below their pour points, but the

design and operation of a pipeline under these conditions presents special problems.)

Vapour Pressure. (The pressure that holds a volatile liquid in equilibrium with its vapour at agiven temperature is its vapour pressure; when page 73 determined for petroleum products under

specific test conditions and using specific procedures it is called the RVP (Reid Vapour Pressure). Vapour pressure is an especially important design criterion when handling volatile

petroleum products such as propane or butane.

The minimum pressure in the pipeline must be high enough to maintain these fluids in their liquid state.

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R eynolds Number, which is a dimensionless number, which is used to describe the type of flowexhibited by a flowing fluid. In streamlined (or laminar) flow, the molecules move parallel to the

axis of flow. In turbulent flow, the molecules move back and forward across the flow axis. Other types of flow are also possible and the Reynolds number can be used to determine which types of

flow are likely to occur under specified conditions. In turn, the type of flow exhibited by a fluid

affects pressure drop in the pipeline. Strictly speaking. a Reynolds Number below 1000 describesstreamlined flow.

At Reynolds Numbers between 1000 and 2000 flow is unstable. At Reynolds Numbers greater than 2000 flow is turbulent These figures are not always used. In general usage, how is

considered laminar for R<2000,>4000.

Friction Factor. (A variety of friction factors are used in pipeline calculations. They aredetermined empirically and are related to the roughness of the inside pipe wall)

This is not a complete list but represents the basic parameters used. Terms are interdependent;

for example, operation pressure depends on pressure drop, which depends on flow rate, which inturn is dictated by allowable pressure drop.

Several pressure terms are used in pipeline design and operation. Barometric pressure is the

value of the atmospheric pressure above a perfect vacuum. A perfect vacuum cannot exist on theearth, but it makes a convenient reference point for pressure measurement.

Absolute pressure is the pressure of a pipeline or vessel above a perfect vacuum and is

abbreviated bara. Gauge pressure is the pressure measured in a pipeline or vessel aboveatmospheric pressure and is abbreviated barg. Standard atmospheric pressure is usualIy

considered to be the head pressure of 760 mm of mercury, but atmospheric pressure varies withelevation above sea level. Many contracts for the purchase of natural gas, for instance, specify

that the standard, or base, pressure will be other than 760mm/kg.

Formulas describing the flow of fluids in a pipe are derived from Bernoulli¶s theorem and aremodified to account for losses due to friction. Bernoulli¶s theorem expresses the application of

the law of conservation of energy to the flow of fluids in a conduit To describe the actual flow of gases and liquids properly, howeyer, solutions based on Bernoulli¶s theorem require the use of

coefficients that must be determined experimentally.

As a basic rule, the amount of flow along a pipeline (or across any restriction) will be a functionof the differential pressure. The basic equation is:

%Q = ¥% Dp x 10

where:

0= Flow (In %)

Dp = Differential pressure (in %)



The theoretical equation for fluid flow neglects friction and assumes no energy is added to the

systems by pumps or compressors. Of course, in the design and operation of a pipeline, frictionlosses are very important, and pumps and compressors are required to overcome those losses. So

practical pipeline design equations depend on empirical coefficients that have been determined

during years of research and testing.

The basic theory of fluid flow does not change. But modifications continue to be made in

coefficient as more information is available, and the application of various forms of basicformulas continues to be refined. The use of computers for solving pipeline design problems has

also enhanced the accuracy and inflexibility possible in pipeline design.

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In the design of liquids and natural gas pipelines, pressure drop, flow capacity and pumping or

compression horsepower required are key calculations. The design of a liquids pipeline is similar in concept to the design of a natural gas pipeline. In both cases, a delivery pressure and the

volume the pipeline must handle are known. The allowable working pressure of the pipe can bedetermined using the pipe size and type and specified safety factors.

In most pipeline calculations, assumptions must be made initially. For instance, a line size may

be assumed in order to determine maximum operating pressure and the pressure drop in a givenlength of pipe for a given flow volume. If the resulting pressure drop, when added to the known

delivery pressure exceeds the allowable working pressure, a larger pipe size must usually bechosen.

It may be possible to change the capacity and spacing of booster pumping stations to stay within

operating pressure. But in the simplest case, if the calculation yields an operating pressuregreater than allowed, a larger pipe size must be selected and the calculation repeated.

It is apparent that many options are available in even a moderately complex pipeline system. But

today¶s computer programs for pipeline design can analyze many variables and many options ina short time, greatly easing the design process.

4.5.2.3 Pressure Drop

An equation for the flow of liquids in a pipe was developed by Darcy in the early 18th Century

and the equations, formulae and standards defined by Darçy are still valid today.

The Darcy equation can be derived mathematically (except for a friction factor which must bedetermined by experiment) and can be used to calculate for laminar and turbulent flow of liquid

in a pipe.

4.5.2.4 Valves And Fittings



In addition to the pressure loss due to fluid friction with the walls of the pipeline, valves andfittings also contribute to overall system pressure loss. The pressure loss due to a single valve in

several thousand feet of straight piping will be insignificant but in a pumping station, for example, where many valves exist and many changes in flow direction occur, pressure loss in

valves and fittings is important Pressure loss in valves and fittings is made up of both the friction

loss within the valve or fitting itself and the additional loss upstream and downstream of thefitting above that which would have occurred in the absence of the fitting. Calculation of the pressure loss in a valve or fitting is based on experimental data. One approach is the use of a

resistance factor for a given valve or fitting. The resistance coefficient is normally treated as aconstant for a given valve or fitting under all flow conditions.

Another term used in determining the pressure drop through valves and fittings is the flow

coefficient, Cv The flow coefficient of a valve is the flow of water at 6OºF, in gal/min, ata pressure drop of one psi across the valve. The flow coefficients of any other liquid can be

calculated using the relation of itsdensity to that of water.

4.5.2.5 Heavy Crudes

Some crudes with very high pour points or high wax contents that require pipelines of special

design Pipelining such crudes can be especially troublesome offshore where heat loss to thewater is great and any heat added to the crude before it enters the pipeline is dissipated within a

short distanceif a conventional pipeline is used. If the crude cools, excessive wax deposits in the pipeline can

lower operating efficiency. In cases of extremely viscous crudes, flow can even be halted if thetemperature is allowed to fail too low. Not only is the baiting of flow a problem, but restarting

flow after such an occurrence can be difficult. To handle these special crudes, pipelines have been successfully installed and operated simply by insulating the pipelines, but other approaches

include:

Heating the crude to a high temperature at the inlet to the pipeline, allowing it to reach its ndestination before cooling below the pour point (The pipeline may or may not be insulated);

Pumping the crude at a temperature below the pour point using high pressure pumps;

Adding a hydrocarbon dilutant such as a less waxy crude or a light distillate;

Injecting water to form a layer between the pipe wall and the crude;

Processing the crude before pipelining to change the wax crystal structure and reduce pour

point and viscosity.

Mixing water with the crude to form an emulsion; Processing the crude before pipelining tochange the wax crystal structure and reduce pour point and viscosity;

Heating both crude and pipeline by steam tracing or electrical heating;



Injecting wax solvents such as benzene or toluene.

A combination of these methods can also be used and the choice of method will depend upon the

physical properties of the crude and the economics of its production.

If waxy crude is pumped below its pour point, more pumping energy is required and, if pumpingis stopped, more energy will be required to put the crude in motion again than was required to

keep it flowing.

When flow is stopped wax crystals form, causing the crude to gel in the pipeline.The wax incrude which is being pumped at temperatures above its pour point will form cohesive lattice

structures if it is allowed to cool down to below its pour point whilst stationary. Experimentshave shown that restart pressures can be five to ten times higher for a pipeline that was above the

pour point and cooled after shut-down than for one that was below its pour point before shut-down.

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4.5.2.6 Gas Pipelines

Several formulae can be used to calculate the flow of gas in a pipeline. These formulas accountfor the effects of pressure, temperature, pipe diameter, pipe length, specific gravity, pipe

roughness and gas deviation.

The Darcy equation can also be used in flow calculations involving gases but it must be donewith care and restrictions on its use are recommended. If, for instance, pressure drop in the line is

large relative to the inlet pressure, the Darcy equation is not recommended. Because this is oftenthe case and because other restrictions also apply to its use in gas flow calculations, other more

practical equations are commonly used for gas flow calculations.

4.5.2.7 Allowable Operating Pressure

An important pipeline design calculation is the maximum pressure at which a given size, gradeand weight of pipe may operate.

Maximum operating pressure determines how much a pipeline may carry . Other factors beingfixed and depends on the physical and chemical properties of the pipe steel. Since standard pipe

grades, sizes and weights are normally used, the maximum operating pressure can usually beobtained from tables

contained in recognised specifications.

4.5.2.8 Looping

This is the term used when laying a pipeline parallel to an existing line in order to increase thetotal capacity throughput.

4.5.2.9 Two-phase Flow



The combined flow of oil and gas in a pipeline presents many design and operational difficultiesnot

present in single phase liquid or vapour flow. Frictional pressure drops are harder to estimate.

Liquid is likely to gather at low points in the pipeline and reduce the pipeline capacity to a point

when slugs of liquid are pushed ahead by the gas.

The movement of large liquid slugs along the pipeline can cause additional pipeline stresses and

the pipeline terminal facilities must be designed to receive such volumes of liquid by provisionof large, specially designed vessels or energy absorbing pipework, known as slug-catchers.

The type of flow in a pipe is known as its flow regime. We have already come across laminar

and turbulent flow regimes. These are single phase flow regimes and which phase will exist can be found by calculating the Reynolds number.

Pipelines are seldom horizontal, as they have to follow the undulations of the seabed or the

countryside, and often have vertical sections as they rise to join platforms or enter processstreams.

In view of this, flows regimes can exist which are considerably more complex than those already

discussed.

The key difference between single-phase flow and two-phase flow is that it is much moredifficult to determine pressure drops for two-phase flow. This is complicated if you consider that

a difference in incline of several degrees, never mind 90º; can change entirely the natureof the flow regime.

Undulating terrain will generally not be a problem for single-phase pipelines; however, it can

materially affect pressure drop in two-phase pipelines if there are a large number of. rises andfalls, which the pipeline must cross.

Some two-phase regimes are caused by liquid condensation or fall-out from the gas due to

reducing temperature and pressure along the length of the pipeline. For onshore gas lines liquidknock-outs can be provided at intervals such that liquids can be drained off by blow-down of the

line.

Well flow lines often work in a two-phase regime, particularly because the well fluids usuallycontain both oil and gas and there may be no facility at the wellhead (E.g. at sub-sea wells) prior

to the fluid reaching the gathering station (or platform).

Despite the problems associated with the prediction of two-phase estimates, more and more pipelines are being designed for such flow systems.

For example when hydrocarbon condensate is separated from the gas at offshore platforms, it is

invariably spiked back into the gas for transport to the shore in the pipeline. This is mainly because te economics would not support a separate line for condensate sales.



Several empirical flow patterns have been presented that determine vapour/liquid flow as a

function of fluid proportions and flow rates. Diagrams of these flow patterns are shown Figure.

Care should be taken in the interpretation of these diagrams, as the regime boundaries of bubble,slug, annular, mist and wave conditions are strongly affected by pipe inclination. Even very low

pipe inclination of one or two degrees can cause considerable movement of the regime boundaries and, in

addition, adjustment has been observed due to fluid pressure, pipe diameter and surface tension.

In both vertical and horizontal directions, the avoidance of slug flow is desirable. Slug flow

might possibly be avoided by choice of a smaller pipe diameter. This will increase fluidvelocities and reduce the pipeline liquid inventory.

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4.5.3 Sizing Of Pipelines

4.5.3.1 Oil Pipelines

Pumping a specified quantity of a given oil over a given distance may be achieved by using alarge diameter pipe with a small pressure drop, or small diameter pipe with a greater pressure

drop.

The first alternative will tend to a higher capital cost with lower running costs. It is necessary tostrike an economic balance between these two.



There are no hard and fast rules, which can be laid down for achieving this balance. For instance,

a pumping station in a populated area may consist of a simple building, involving the provisionof electrically driven pumps, taking power from outside sources and little else. To obtain the

same pumping power in remote or undeveloped countries would involve a considerably more

complicated and expensive installation. Obviously in this latter case, it is desirable to reduce thenumber of pumping stations at the cost of using larger diameter piping.

Similarly, the cost of the pipeline will vary considerably, depending upon circumstances. It will be costly in highly industrialised areas, environmentally sensitive areas, offshore or in hostile,

mountainous or swamp areas; cheaper in flat, soft but firm, undeveloped terrain.

4.5.3.2 Gas Pipelines

Sizing problems encountered in gas lines differ considerably from those of oil lines. Asimplification results from the negligible weight of the gas as the pressure in the line is virtually

independent of the ground elevation on the other hand, the compressibility of gas introduces thecomplication of the density decreasing and consequently the volume rate of flow increasing in

the direction of flow. In an oil line of constant diameter laid on level ground, the pressuredecreases uniformly with distance and the velocity stays constant whereas, in a gas line, the

velocity increases as the pressure gradient decreases with an exponential, which becomes progressively steeper.

The characteristics of pumps and compressors also determine the site of any pipeline booster

stations as well as the initial pipeline conditions which have to be met Pumps need to be sited in positions where they are receiving the crude oil at a pressure greater than the vapour pressure of

the crude oil, whereas compressors have to be sited at a location where both the pressure andvelocity of the gas are at optimum conditions.

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4.5.5 Pipeline Construction

4.5.5.1 Pipeline Design Codes

Most of the codes of practice are derivatives from studies conducted by the American Society of

Mechanical Engineers (ASMIE) and the American Standards Association (ASA), which later changed its name to the American National Standards Institute (ANSI).

The UK Pipeline Safety Code is Part 6 of the IP Model code of Safe Practice in the Petroleumindustry, which includes and takes note of the British Standard Code of Practice for Pipelines,BS CP 2010, which relates to pipeline construction in the UK.

Gas distribution lines up to a working pressure of 70 bar are adequately covered by the

Institution of Gas Engineers¶ series ³Recommendations on Transmission and DistributionPractice. The IIP Code does not claim to be a design handbook and does not replace the need for

appropriate experience and engineering judgment.



The IP Code of Practice sets forth general requirements for the safe design, construction and

operation of pipelines for the conveyance of petroleum (crude oil and liquid products) and gas(natural gas and gaseous products).

It specifies considerations for pipe materials, flanges fittings and valves etc.

Submarine pipelines are designed to internationally accepted codes, such as in Norway the Det

Norske Veritas ³Rules for the Design, Construction and Inspection of Submarine Pipelines andPipeline Risers´.

By definition pipelines normally start at the scraper launcher and ends at the scraper receiver or

slug catcher.

It should be remembered that wherever national codes are more stringent than internationallyaccepted codes, the national codes must take precedence.

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4.5.5.2 Grades of Steel

The pipe from which flow lines and pipelines are constructed is known in the oil industry as³1ine pipe´. As with casing and tubing, line pipe is manufactured from different grades or

strengths of steel and in different wall thickness to enable economical as well as safe design. The physical properties of the various grades of steels used in the manufacture of most of the line

pipe of importance to the industry are set out in API Standards.

The requirement for high pressure, large diameter, cross-country, oil and gas transmission linesdeveloped a need for a high strength, field weldable steel. As a result, API grades X-42 through

X-65 with yield strengths of 42,000 psi to 65,000 psi were developed. These higher strengthsteels are available for use under the requirements of the IP Code.

The higher working pressures resulting from the use of the higher strength steels enable a

substantial saving in steel tonnage and can be economical in use.

Submarine pipelines are subject to external stresses not considered so far in our discussions. Inaddition to hydrostatic pressure due to immersion depth, the motion of the sea introduces

currents and swell and possibly thermal stress. During and after laying greater considerationmust be given to the weight and curvature of the pipe.

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4.5.5.3 Process of Manufacture

Three different processes are used to manufacture pipe that is used for line pipe. The propertiesand capabilities of the pipe vary with the type of process used.

4.5.5.4 Seamless Line Pipe



Seamless pipe is generally the industries first choice for high-pressure flow lines and pipelines.

Seamless pipe is a wrought steel tube without a welded seam, manufactured by hot working steel

and, if necessary, subsequently cold finished to produce the desired properties.

Generally speaking, seamless pipe is preferred by the oil industry for use in well flow lines andother high pressure lines, although welded pipe described below is similarly used for high

pressure lines in larger sizes where seamless pipe is not available. Availability is limited to amaximum diameter of about 20

inches because of the process of forming seamless pipe.

4.5.5.5 Furnace Welded Line Pipe

About the only type of furnace welded pipe available today is manufactured by the continuouswelding, butt-weld process.

In the butt-weld process, pipe is manufactured with one longitudinal seam formed by mechanical

pressure to make the welded junction after the entire steel strip from which the tube is formedhas been heated to proper welding temperature.

The cost of the CW, continuous weld, butt weld line pipe is 15 to 20% lower than Grade B

seamless or electric weld line pipe.

4.5.5.6 Electric Welded Line Pipe

Electric welded pipe has one longitudinal seam formed by electric flash welding, electricresistance welding or electric induction welding without the addition of extraneous metal. There

is probably more pipe manufactured by the electric weld process than any other method becauseof the low initial

investment for the equipment and the adaptability to different wall thicknesses. Most electricweld line pipe is not fully normalised after welding. Some is normalised in the weld zone only.

Therefore, there is a heat runout zone on each side of the weld resulting in non-uniformity of hardness and grain structure.

Like furnace weld, electric weld is not recommended for use where internal corrosion is

expected.

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Steel pipes are referred to according to their nominal inside diameter up to 12 in. Pipes of above

12 diameter are usually identified by their outside diameter (OD). All classes (weights) of pipe of a given nominal size have the same OD, the extra thickness for different weights being on the

inside.



4.5.5.8 Pipe End Connections

Flow lines and pipelines are normally constructed with plain-end or bevelled and pipe ready for field welding. Where occasionally flanged connections are required, for example where flanged

spools or block valves are fitted, the flanges will generally be specified raised face to ANSI

B16.5, or its equivalent BS 1560, with weld-neck ends.

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4.5.6 Pipe Coating and Protection

4.5.6.1 Land Pipelines

Before being trenched and buried, the pipe is normally cleaned and coated with a1ayer of bitumen, fusion-bonded epoxy or other type material for external corrosion protection. Many

types of coating, some proprietary, are available and the type of soil influences the choice of coating. The coating is normally wrapped with tape for physical protection of the coating during

subsequent operations.

4.5.6.2 Submarine Pipelines

Subsea immersion causes the pipeline to be exposed to a corrosive environment that is normallyvery severe. Pipe coating must be applied under stringent conditions with good mechanical

strength to withstand the subsequent laying operations. Concrete coating is frequently necessaryto provide negative buoyancy. Trenching may be necessary as dictated by the authorities for

coastal areas, inland swamp areas, shallow waters and shipping lanes.

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4.5.8 Pipeline Pigging

4.5.8.1 General

Pipeline pigs and spheres are used for a variety of purposes in both liquids and natural gas

pipelines.

Pigs and spheres are forced through the pipeline by the pressure of the flowing fluid. A pigusually consists of a steel body with rubber or plastic cups attached to seal against the inside of

the pipeline and to allow pressure to move the pig along the pipeline. Different types of brushesand scrapers can be attached to the body of the pig for cleaning or to perform other functions.

Figure 4.28 illustrates a variety of pipeline pigs



Pipeline pigging is done for the following reasons:

To clean up pipelines before use (foam pigs);

To fill lines for hydrostatic testing, dewatering following hydrostatic testing, and drying and

purging operations (spheres and foam pigs);

To periodically remove wax, dirt and water from the pipeline (scraper pigs and brush pigs);

To sweep liquids from gas pipelines (spheres)

To separate products to reduce the amount of mixing between different types of crude oil or

refined products (squeegee pigs and ³Go-Devil´ pigs);

To control liquids in a pipeline, including two-phase pipelines (spheres and foam pigs);

To inspect pipelines for defects such as dents, buckles or corrosion (³intelligent-pigs or caliper

pigs).

(Figure 4.29 illustrates a kaliper pig.)



Differential pressure is required to move a pig or sphere through the pipeline. The force requireddepends on elevation changes in the pipeline, friction between the pig and the pipe wall and the

amount of lubrication available in the line. (A dry gas pipeline provides less lubrication tan acrude oil pipeline, for example).

Cups are designed to seal against the wall by making them larger than the inside diameter of the pipe. As the cups become worn, the amount of blow-by fluid by-passing the pigs increases because the seal is not as effective.

In the case of spheres, a certain amount of over-inflation is required to provide a seal. (In two- phase pipelines, spheres are sometimes under-inflated to allow some blow-by to lower the

density of the fluid ahead of the sphere).

Pigs and spheres travel at about the same velocity as the fluid in the pipeline and travel speed isrelatively cons

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Pig launching and receiving procedures are often supervised by senior operations staff and fullymonitored by all pipeline users but the actual procedures laid down for each pig launching/pig

receiving facility will vary.

4.5.8.5 Pigging Problems



The pig launcher-receiver is probably the only high-pressure vessel on the facility, in

hydrocarbon service, which is regularly opened to the atmosphere and then pressured as a normaloperating procedure.

If the launcher/receiver is incorrectly purged and pressured, an explosion becomes a major possibility. To reduce the chances of such an incident, the relative procedures are commonly backed up by an ³interlock-system´, which prevents the movement of valves and door closure

devices until certain criteria have been met within the system.

Figure 4.33 illustrates the logic of a simple interlock system.

In the last decade at least two launchers have been involved in major explosions in Britain.

When pigs are launched into a pipeline there is always the possibility that the pig will stop or

reduce the flow of fluid through the pipeline. The most common incidents and their causes are:

The pig fails to launch (this only becomes apparent alter the launch procedure is at its finalstages. The possible causes are:

1. The pig is too small (wrong pig or under- sized) and the flow cannot pick up the pig in the

launcher barrel.

2. The pig is too large, wrong pig or oversized and it is jammed in the exit to the launcher.



3. The pig is too far back in the launcher.

The pig indicator, Figure 4.35 should show that the pig has launched. They are, however, notalways reliable.

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Pipes and Fittings Standards

The ASME - American Society of Mechanical Engineers - ASME/ANSI B16 Standards covers pipes and fittings in cast iron , cast bronze, wrought copper and steel.

ASME/ANSI B16.1 - 1998 - Cast Iron Pipe Flanges and Flanged Fittings

This Standard for Classes 25, 125, and 250 Cast Iron Pipe Flanges and Flanged Fittingscovers:

* (a) pressure-temperature ratings,* (b) sizes and method of designating openings of reducing fittings,* (c) marking,

* (d) minimum requirements for materials,* (e) dimensions and tolerances,

* (f) bolt, nut, and gasket dimensions and* (g) tests.



ASME/ANSI B16.3 - 1998 - Malleable Iron Threaded Fittings

This Standard for threaded malleable iron fittings Classes 150, and 300 provides requirementsfor the following:

* (a) pressure-temperature ratings* (b) size and method of designating openings of reducing fittings* (c) marking

* (d) materials* (e) dimensions and tolerances

* (f) threading* (g) coatings

ASME/ANSI B16.4 - 1998 - Cast Iron Threaded Fittings

This Standard for gray iron threaded fittings, Classes 125 and 250 covers:

* (a) pressure-temperature ratings

* (b) size and method of designating openings of reducing fittings* (c) marking

* (d) material* (e) dimensions and tolerances

* (f) threading, and* (g) coatings

ASME/ANSI B16.5 - 1996 - Pipe Flanges and Flanged Fittings

The ASME B16.5 - 1996 Pipe Flanges and Flange Fittings standard covers pressure-temperature

ratings, materials, dimensions, tolerances, marking, testing, and methods of designating openingsfor pipe flanges and flanged fittings.

The standard includes flanges with rating class designations 150, 300, 400, 600, 900, 1500, and

2500 in sizes NPS 1/2 through NPS 24, with requirements given in both metric and U.S units.The Standard is limited to flanges and flanged fittings made from cast or forged materials, and

blind flanges and certain reducing flanges made from cast, forged, or plate materials. Alsoincluded in this Standard are requirements and recommendations regarding flange bolting, flange

gaskets, and flange joints.

ASME/ANSI B16.9 - 2001 - Factory-Made Wrought Steel Buttwelding Fittings

This Standard covers overall dimensions, tolerances, ratings, testing, and markings for wroughtfactory-made buttwelding fittings in sizes NPS 1/2 through 48 (DN 15 through 1200).

ASME/ANSI B16.10 - 2000 - Face-to-Face and End-to-End Dimensions of Valves

This Standard covers face-to-face and end-to-end dimensions of straightway valves, and center-



to face and center-to-end dimensions of angle valves. Its purpose is to assure installationinterchangeability for valves of a given material, type size, rating class, and end connection

ASME/ANSI B16.11 - 2001 - Forged Steel Fittings, Socket-Welding and Threaded

This Standard covers ratings, dimensions, tolerances, marking and material requirements for forged fittings, both socket-welding and threaded.

ASME/ANSI B16.12 - 1998 - Cast Iron Threaded Drainage Fittings

This Standard for cast iron threaded drainage fittings covers:

* (a) size and method of designating openings in reducing fittings* (b) marking

* (c) materials* (d) dimensions and tolerances

* (e) threading* (f) ribs

* (g) coatings* (h) face bevel discharge nozzles, input shafts, base plates, and foundation bolt holes (see

Tables 1 and 2).

ASME/ANSI B16.14 - 1991 - Ferrous Pipe Plugs, Bushings and Locknuts with PipeThreads

This Standard for Ferrous Pipe Plugs, Bushings, and Locknuts with Pipe Threads covers:

* (a) pressure-temperature ratings:

* (b) size;* (c) marking;

* (d) materials;* (e) dimensions and tolerances;

* (f) threading; and* (g) pattern taper.

ASME/ANSI B16.15 - 1985 (R 1994) - Cast Bronze Threaded Fittings

This Standard pertains primarily to cast Class 125and Class 250 bronze threaded pipe fittings.

Certain requirements also pertain to wrought or cast plugs, bushings, couplings, and caps. ThisStandard covers:

* (a) pressure-temperature ratings;

* (b) size and method of designating openings of reducing pipe fittings;* (c) marking;

* (d) minimum requirements for casting quality and materials;* (e) dimensions and tolerances in U.S. customary and metric (SI) units;



* (f) threading.

ASME/ANSI B16.18 - 1984 (R 1994) - Cast Copper Alloy Solder Joint Pressure Fittings

This Standard for cast copper alloy solder joint pressure fittings designed for use with copper

water tube, establishes requirements for:

* (a) Pressure-temperature ratings;

* (b) Abbreviations for end connections;* (c) Sizes and method of designating openings of fittings;

* (d) Marking;* (e) Material;

* (f) Dimensions and tolerances; and* (g) Tests.

ASME/ANSI B16.20 - 1998 - Metallic Gaskets for Pipe Flanges-R ing-Joint, Spiral-Would,

and Jacketed

This standard covers materials, dimensions, tolerances, and markings for metal ring-jointgaskets, spiral-wound metal gaskets, and metal jacketed gaskets and filler material. These

gaskets are dimensionally suitable for used with flanges described in the reference flangestandards ASME/ANSI B16.5, ASME B16.47, and API-6A. This standard covers spiral-wound

metal gaskets and metal jacketed gaskets for use with raised face and flat face flanges. ReplacesAPI-601 or API-601.

ASME/ANSI B16.21 - 1992 - Nonmetallic Flat Gaskets for Pipe Flanges

This Standard for nonmetallic flat gaskets for bolted flanged joints in piping includes:

* (a) types and sizes;

* (b) materials;* (c) dimensions and allowable tolerances.

ASME/ANSI B16.22 - 1995 - Wrought Copper and Copper Alloy Solder Joint PressureFittings

The Standard establishes specifications for wrought copper and wrought copper alloy, solder- joint, seamless fittings, designed for use with seamless copper tube conforming to ASTM B 88

(water and general plumbing systems), B 280 (air conditioning and refrigeration service), and B819 (medical gas systems), as well as fittings intended to be assembled with soldering materials

conforming to ASTM B 32, brazing materials conforming to AWS A5.8, or with tapered pipethread conforming to ASME B1.20.1. This Standard is allied with ASME B16.18, which covers

cast copper alloy pressure fittings. It provides requirements for fitting ends suitable for soldering.This Standard covers:

* (a) pressure temperature ratings;



* (b) abbreviations for end connections;* (c) size and method of designating openings of fittings;

* (d) marking;* (e) material;

* (f) dimension and tolerances; and

* (g) tests.

ASME/ANSI B16.23 - 1992 - Cast Copper Alloy Solder Joint Drainage Fittings (DWV)

The Standard establishes specifications for cast copper alloy solder joint drainage fittings,

designed for use in drain, waste, and vent (DWV) systems. These fittings are designed for usewith seamless copper tube conforming to ASTM B 306, Copper Drainage Tube (DWV), as well

as fittings intended to be assembled with soldering materials conforming to ASTM B 32, or tapered pipe thread conforming to ASME B1.20.1. This standard is allied with ASME B16.29,

Wrought Copper and Wrought Copper Alloy Solder Joint Drainage Fittings - DWV. It providesrequirements for fitting ends suitable for soldering. This standard covers:

* (a) description;

* (b) pitch (slope);* (c) abbreviations for end connections;

* (d) sizes and methods for designing openings for reducing fittings;* (e) marking;

* (f) material; and* (g) dimensions and tolerances.

ASME/ANSI B16.24 - 1991 (R 1998) - Cast Copper Alloy Pipe Flanges and Flanged Fittings

This Standard for Classes 25, 125, 250, and 800 Cast Iron Pipe Flanges and Flanged Fittings

covers:

* (a) pressure temperature ratings,* (b) sizes and methods of designating openings for reduced fittings,

* (c) marking,* (d) minimum requirements for materials,

* (e) dimensions and tolerances,* (f) bolt, nut, and gasket dimensions, and

* (g) tests.

ASME/ANSI B16.25 - 1997 - Buttwelding Ends

* The Standard covers the preparation of butt welding ends of piping components to be joinedinto a piping system by welding. It includes requirements for welding bevels, for external and

internal shaping of heavy-wall components, and for preparation of internal ends (includingdimensions and tolerances). Coverage includes preparation for joints with the following.

* (a) no backing rings;* (b) split or non continuous backing rings;



* (c) solid or continuous backing rings;* (d) consumable insert rings;

* (e) gas tungsten are welding (GTAW) of the root pass. Details of preparation for any backingring must be specified in ordering the component.

ASME/ANSI B16.26 - 1988 - Cast Copper Alloy Fittings for Flared Copper Tubes

This standard for Cast Copper Alloy Fitting for Flared Copper Tubes covers:

* (a) pressure rating;

* (b) material;* (c) size;

* (d) threading;* (e) marking.

ASME/ANSI B16.28 - 1994 - Wrought Steel Buttwelding Short R adius Elbows and R eturns

This Standard covers ratings, overall dimensions, testing, tolerances, and markings for wrought

carbon and alloy steel buttwelding short radius elbows and returns. The term wrought denotesfittings made of pipe, tubing, plate, or forgings.

ASME/ANSI B16.29 - 1994 - Wrought Copper and Wrought Copper Alloy Solder JointDrainage Fittings (DWV)

The standard for wrought copper and wrought copper alloy solder joint drainage fittings,designed for use with copper drainage tube, covers:

* (a) Description,

* (b) Pitch (slope),* (c) Abbreviations for End Connections,

* (d) Sizes and Method of Designating Openings for Reducing Fittings,* (e) Marking,

* (f) Material,* (g) Dimensions and Tolerances.

ASME/ANSI B16.33 - 1990 - Manually Operated Metallic Gas Valves for Use in Gas PipingSystems Up to 125 psig

General This Standard covers requirements for manually operated metallic valves sizes NPS 1.2through NPS 2, for outdoor installation as gas shut-off valves at the end of the gas service line

and before the gas regulator and meter where the designated gauge pressure of the gas pipingsystem does not exceed 125 psi (8.6 bar). The Standard applies to valves operated in a

temperature environment between .20 degrees F and 150 degrees F (.29 degrees C and 66degrees C). Design This Standard sets forth the minimum capabilities, characteristics, and

properties, which a valve at the time of manufacture must possess, in order to be consideredsuitable for use in gas piping systems.



ASME/ANSI B16.34 - 1996 - Valves - Flanged, Threaded, and Welding End

This standard applies to new valve construction and covers pressure-temperature ratings,

dimensions, tolerances, materials, nondestructive examination requirements, testing, and

marking for cast, forged, and fabricated flanged, threaded, and welding end, and wafer or flangeless valves of steel, nickel-base alloys, and other alloys shown in Table 1. Wafer or flangeless valves, bolted or through-bolt types, that are installed between flanges or against a

flange shall be treated as flanged end valves.

ASME/ANSI B16.36 - 1996 - Orifice Flanges

This Standard covers flanges (similar to those covered in ASME B16.5) that have orifice pressure differential connections. Coverage is limited to the following:

* (a) welding neck flanges Classes 300, 400, 600, 900, 1500, and 2500

* (b) slip-on and threaded Class 300

* Orifice, Nozzle and Venturi Flow Rate Meters

ASME/ANSI B16.38 - 1985 (R 1994) - Large Metallic Valves for Gas Distribution

The standard covers only manually operated metallic valves in nominal pipe sizes 2 1/2 through12 having the inlet and outlet on a common center line, which are suitable for controlling the

flow of gas from open to fully closed, for use in distribution and service lines where themaximum gage pressure at which such distribution piping systems may be operated in

accordance with the code of federal regulations (cfr), title 49, part 192, transportation of naturaland other gas by pipeline; minimum safety standard, does not exceed 125 psi (8.6 bar). Valve

seats, seals and stem packing may be nonmetallic.

ASME/ANSI B16.39 - 1986 (R 1998) - Malleable Iron Threaded Pipe Unions

This Standard for threaded malleable iron unions, classes 150, 250, and 300, providesrequirements for the following:

* (a) design

* (b) pressure-temperature ratings* (c) size

* (d) marking* (e) materials

* (f) joints and seats* (g) threads

* (h) hydrostatic strength* (i) tensile strength

* (j) air pressure test* (k) sampling



* (l) coatings* (m) dimensions

ASME/ANSI B16.40 - 1985 (R 1994) - Manually Operated Thermoplastic Gas

The Standard covers manually operated thermoplastic valves in nominal sizes 1.2 through 6 (asshown in Table 5). These valves are suitable for use below ground in thermoplastic distributionmains and service lines. The maximum pressure at which such distribution piping systems may

be operated is in accordance with the Code of Federal Regulation (CFR) Title 49, Part 192,Transportation of Natural and Other Gas by Pipeline; Minimum Safety Standards, for

temperature ranges of .20 deg. F to 100 deg. F (.29 deg. C to 38 deg. C). This Standard setsqualification requirements for each nominal valve size for each valve design as a necessary

condition for demonstrating conformance to this Standard. This Standard sets requirements for newly manufactured valves for use in below ground piping systems for natural gas [includes

synthetic natural gas (SNG)], and liquefied petroleum (LP) gases (distributed as a vapor, with or without the admixture of air) or mixtures thereof.

ASME/ANSI B16.42 - 1998 - Ductile Iron Pipe Flanges and Flanged Fittings, Classes 150and 300

The Standard covers minimum requirements for Class 150 and 300 cast ductile iron pipe flangesand flanged fittings. The requirements covered are as follows:

* (a) pressure-temperature ratings

* (b) sizes and method of designating openings* (c) marking

* (d) materials* (e) dimensions and tolerances

* (f) blots, nuts, and gaskets* (g) tests

ASME/ANSIB16.44 - 1995 - Manually Operated Metallic Gas Valves for Use in HousePiping Systems

This Standard applies to new valve construction and covers quarter turn manually operatedmetallic valves in sizes NPS 1/2-2 which are intended for indoor installation as gas shutoff

valves when installed in indoor gas piping between a gas meter outlet & the inlet connection to agas appliance.

ASME/ANSI B16.45 - 1998 - Cast Iron Fittings for Solvent Drainage Systems

The Standard for cast iron drainage fittings used on self-aerating, one-pipe Solvent drainagesystems, covers the following:

* (a) description

* (b) sizes and methods for designating openings for reducing fittings* (c) marking



* (d) material* (e) pitch

* (f) design* (g) dimensions and tolerances

* (h) tests

ASME/ANSI B16.47 - 1996 - Large Diameter Steel Flanges: NPS 26 through NPS 60

This Standard covers pressure-temperature ratings, materials, dimensions, tolerances, marking,and testing for pipe flanges in sizes NPS 26 through NPS 60 and in ratings Classes 75, 150,0300,

400, 600, and 900. Flanges may be cast, forged, or plate (for blind flanges only) materials.Requirements and recommendations regarding bolting and gaskets are also included.

ASME/ANSI B16.48 - 1997 - Steel Line Blanks

The Standard covers pressure-temperature ratings, materials, dimensions, tolerances, marking,

and testing for operating line blanks in sizes NPS 1/2 through NPS 24 for installation betweenASME B16. 5 flanges in the 150, 300, 600, 900, 1500, and 2500 pressure classes.

ASME/ANSI B16.49 - 2000 - Factory-Made Wrought Steel Buttwelding Induction Bendsfor Transportation and Distribution Systems

This Standard covers design, material, manufacturing, testing, marking, and inspectionrequirements for factory-made pipeline bends of carbon steel materials having controlled

chemistry and mechanical properties, produced by the induction bending process, with or without tangents. This Standard covers induction bends for transportation and distribution piping

applications (e.g., ASME B31.4, B31.8, and B31.11) Process and power piping have differingrequirements and materials that may not be appropriate for the restrictions and examinations

described herein, and therefore are not included in this Standard.

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Pipe Stress Analysis

1.Introduction:

Present day process plant piping systems use various fluids at various conditions of pressure and

temperature. The piping engineer has to design the systems to ensure reliability and safetythroughout designed plant life. The piping systems are subjected to combined effects of fluid

internal pressure, its own weight and restrained thermal expansion. The elevated temperaturealso affects the pipe strength adversely. Therefore the task of the engineer is:

i) To specify an adequate wall thickness to sustain the internal pressure with safety.



ii)To select a piping layout with an adequate flexibility between points of anchorage to absorb its

thermal expansion without exceeding allowable material stress levels, also reacting thrusts andmoments at the points of anchorage must be kept below certain limits.

iii)To limit the additional stresses due to the dead weight of the piping by providing suitablesupporting system- effective for cold as well as hot conditions.

All these objectives are achieved by:

a) Assuming adequate support to prevent excessive sag and stresses in piping system.

b) Incorporating sufficient flexibility to accommodate stress resulting from changes in pipe

length due to thermal effects and movement of the connection at the ends of the pipe.c) Designing the piping system to prevent its exerting excessive forces and movements on

equipment such as pumps and tanks or on other connection and support points.The stress engineer of a piping design department performs the necessary calculations to

ascertain that the various requirements due to internal pressure, thermal expansion and externalweight are satisfied. Various computer packages are available in the market, which perform the

required rigorous analysis. These analyses are basically static analyses. There are situationswhere stresses are introduced into the piping systems due to dynamic loading situations like

reciprocating compressor vibration, safety valve discharge etc. However it is the static analysiswhich most of the pipe stress engineers perform and are acquainted with. Now the present day

computer packages that are being used (CEASAR-II, CAEPIPE, PIPEPLUS etc.) are quitecomprehensive and if the piping configuration and pipe data are fed properly, comprehensive

analysis are done through the computer packages. This has improved pipe stress analysis job productivity immensely. However sometimes this has led to a decline in the knowledge about the

basics of pipe stress analysis especially in situation where the stress analysis engineer after acquiring some sort of skill in the use of the analysis package does not make effort to learn about

the basics of pipe stress. Some of the ideas about the basics of pipe stress have been enumeratedherein.

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2.General ideas on failure of materials:

Failures of material can occur by:

a)Brittle fracture

b)Excessive elastic deformation



c)Excessive non-elastic (plastic or viscous) deformations

d)Thermal or mechanical fatigue.

2.1 Brittle Fracture:

Steel is generally considered to be a ductile material. However in certain cases steels sometimes

rupture without prior evidence of distress. Such brittle failures are accompanied by but little plastic deformation, and the energy required to propagate the fracture appears to be quite low.

The three conditions, which control this tendency for steel to behave in a brittle fashion, include

(1) high stress concentration; i.e. notches, nickes, scratches, internal flows or sharp edges ingeometry

(2) a high rate of straining and

(3) a low temperature.

The transition temperature for any steel is the temperature above, which the steel behaves in a

predominantly ductile manner and below which it behaves in a predominantly brittle maner.Steel with high transition temperature is more likely to behave in a brittle manner during

fabrication or in service. It follows that a steel with low transition temperature is more likely to behave in a ductile manner and therefore, steel with low transition temperature are generally

preferred for service involving severe stress concentrations, impact loading, low temperature or combination of the three.

2.2Elastic and non elastic deformation:

Elastic deformamations are deformations that disappear when the stress is removed. Plastic

deformation is non-reversible. When the stress is removed plastic strain approximately remainsunaltered. A look at the stress strain diagram of say a carbon steel material will clarify the

concepts. However there is another kind of plastic deformation called creep where thedeformation increases with time at constant stress. At certain temperature levels creep, which is



the term, used to describe this progressive deformation may occur in metals even at stress belowthe short time yield strength or proportional limit. Thus the yield strength or proportional limit,

which are determined by short time tensile tests do not represent satisfactory criteria for thedesign of piping systems over the entire temperature range CREEP RATE or CREEP LIMIT

determination through a large number of long time tensile test of elevated temperature becomes

necessary.

2.3Thermal and mechanical fatigue:

Failure has occurred when the service become more severe than the conditions for which the piping was originally designed. Thermal or mechanical fatigue is usually the most common

causes of failures in high temperature piping systems. Severe localized mechanical stress havecaused or contributed to failures.

Thermal fatigue is caused by frequent change in operating temperatures of pipeline. Thermalexpansion and contraction occur in all metal components by the change in temperature. Over a

long period this results in thermal fatigue. Hence for best metallurgical conditions, thetemperature of the high temperature piping systems should be maintained continuously and

uniformly as far as possible.

Mechanical fatigue is caused by pipe movement, vibration, restraints preventing free movement

or other conditions.

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From stress strain diagram of a material like carbon steel we know about yield strength as alsoultimate tensile strength. For our design purpose and allowable stress value is fixed which is

based on a certain factor of safety over the yield strength or ultimate tensile strength. For higher temperature applications creep strength also comes in picture. Various codes detail the allowable

stress basis. The basis adopted in ANSI B31.3 and IBR are described herein. These two codeshave the maximum usage among the Indian pipe stress Engineers for Petrochemical/ Refinery.

3.1 Allowable stress as per ACSI:

As per Petroleum refinery piping code ANSI B31.3 the basic allowable stress values are the min.of the following values.



a)1/3 of the minimum tensile strength at room temp.

b) 1/3 of tensile strength of design temp.c) 2/3 of Min. yield strength of room temp.

d) 2/3 of Min. yield strength at design temp.

e) 100% of average stress for creep rate of O/D 1% per 1000 hr¶s.

3.2 Allowable Stress as per IBR:

As pe the Indian Boiler Regulations the allowable working stress is calculated as shown below:

i) For temperatures at or below 454 Deg.C, the allowable stress is the lower of the followingvalues:

Et = 1.5 or R = 2.7

ii) For temperatures above 454 Deg.C the allowable stress is lower of the

Values:

Et = 1.5 or Sr = 1.5

WhereR = Min. tensile strength of the steel at room temp.

Et = Yield point (02% proof stress) at the temp.Sr = Average stress to produce rupture in 100,000 hr¶s. at a temp. and in

No case more than 1.33 times the lowest stress to produce rupture at temp.Sc = Average stress to produce an elongation of 1% creep in 100,000 hr¶s. All these values have

been made available after carrying on repeated laboratory tests on the specimen.

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The stress of a piping system lowers within the elasticity range in which plastic flow does notoccur by self-spring during several initial cycles even if the calculation value exceeds the yield

point, and thereafter-steady respective stress is applied. Hence repture in a piping system may bedue to low cycle fatigue. It is well known that fatigue strength usually depends upon the mean



stress and the stress amplitude. The mean stress does not always become zero if self spring takes place in piping system but in the ANSI code, the value of the mean stress is disregarded while

the algebraic difference between the maximum and the minimum stress namely only the stressrange SA is employed as the criterion of the strength against fatigue rupture.

The maximum stress range a system could be subjected to without producing flow neither in thecold nor in the hot condition was first proposed by ARC Mark as follows:

a) In cold condition the stress in the pipe material will automatically limit itself to the yieldstrength or 8/5 of Sc because Sc is limited to 5/8th of Y.S. therefore, Ye = 1.6 Sc.

b)At elevated temperatures at which creep is more likely the stress in the pipe material shall itself to the rupture strength i.e. 8/5th

Sh = 1.6 Sh.

Therefore stress range = 1.6f(Sc = Sh)

However, the code limits the stress range conservatively as 1.25f(Sc + Sh) which includes allstresses i.e. expansion ± stress, pressure stress, hot stresses and any other stresses inducted by

external loads such as wind and earthquake, f is the stress range reduction factor for cyclicconditions as given below:

To determine the stress range available for expansion stress alone we subtract the stressesinducted by pressure stress and weight stress which itself cannot exceed sh.

Therefore the range for expansion stress only is

SA = f(1.25 Sc + 0.25 Sh)

VALUES OF FACTOR µ f ¶

Total number of full µ f ¶ factor

Temp. Cycles over expected life7,000 and less 1



14,000 and less 0.922,000 and less 0.8

45,000 and less 0.7100,000 and less 0.6

250,000 and less 0.5

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The code confines the stress examination to the most significant stresses created by the diversityof loading to which a piping system is subjected. They are:

i)Stress due to the thermal expansion of the line.

ii)The longitudinal stresses due to internal or external pressure.

iii)The bending stress created by the weight of the pipe and its insulation, the internal fluid,fittings, valves and external loading such as wind, earthquake etc.

5.1 Stresses due to the thermal expansion of the line:

Temperature change in restrained piping cause bending stresses in single plane systems, and

bending and torsional stresses in three-dimensional system. The maximum stress due to thermal,changes solely is called expansion stress SE. This stress must be within the allowable stress

range SA.

SE = Sb2 + 4St2

Sb = I (Mb / Z) = resulting bending stress

Mt = (Mt //2Z) = torsional stress

Mb = resulting bending movement

Mt / = torsional movement

Z = section modules of pipe



i = stress intensification factor

5.2 Longitudinal stress due to internal or external pressure:

The longitudinal stress due to internal/external pressure shall be expressed as P (Ai / Am)Where Ai is inside cross sectional area of pipe, Am is the metal area, P is the pressure.

5.3 Weight Stress:

The stress induced, self weight of pipe, fluid, fittings etc. as given by SW = M/Z, Where M is

bending moment created by the pipe and other fittings, Z is the section modules of the pipe.

The stresses due to internal pressure and weight of the piping are permanently sustained. They do

not participate in stress reductions due to relaxation and are excluded from the comparison of which as the latter has been adjusted to allow for them with the following provision.

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6.0 Flexibility and stress intensification factor:

Some of the piping items (say pipe elbow) show different flexibility than predicted by ordinary

beam theory. Flexibility factor of a fitting is actually the ratio of rotation per unit length of thefitting in question under certain value of moment to the rotation of a straight pipe of same

nominal diameter and schedule and under identical value of moment. The pipefitting item, whichshows substantial flexibility, is a pipe elbow/bend.

One end is anchored and the other end is attached to a rigid arm to which a force is applied. Theouter fibers of the bend/elbow will be under tension and the inner fibers will be under

compression. Due to shape of bend both tension and compression will have component in thesame direction creating distortion/slottening of bend. This leads to higher flexibility of the end as

there is some decrease in moment of inertia due to distortion from circular to elliptical shape andalso due to fact that the outer layer fibers, which are under tension has to elongate less and the

inner layer fibers which are under compression has to contract less to accommodate the sameangular rotation leading to higher flexibility. Piping component used in piping system has

notches/discontinuities in the piping system, which acts as stress raisers. For example afabricated tee branch. The concept of stress intensification comes from this and is defined as the

ratio of the bending moment producing fatigue failure in a given number of cycles in straight pipe of nominal dimensions to that producing failure in the same number of cycles for the part

under consideration. Both flexibility factor and stress intensification factors have been described



in PROCESS PIPING CODE´(ASME B31.3) and is also included in the various pipe stressanalysis computer programmes.

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7.0 Equipment nozzle loading:

As explained earlier pipe stresses are calculated for various type of loading such as pressure,

weight, thermal etc. and it is reviewed whether the stresses are within allowable limits. However in lot of cases pipe stress analysis becomes critical and rather complicated because it is not only

stress of piping but the nozzle loading of the various equipment which has to be kept withinallowable limits.

For rotating equipment¶s like steam turbines, compressors centrifugal pumps,

various codes like NEMA SM-23, API-617, API-610 etc. give guidelines regarding theallowable nozzle loading. For the analysis of these piping connected with various rotating

equipment, vendor also provide information regarding nozzle movements and allowable loads. Itis the responsibility of the equipment engineer to ensure that the allowable loads as agreed by

vendors are always equal to or greater the values as per the respective applicable code. Variouscomputer packages now have equipment nozzle check features. However the pipe stress

engineers are advised to study the specific applicable codes also as this will give them a further insight for solving specific problems related to equipment nozzle loading.

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General Guidelines for Equipment and Piping Location, Spacing, Distances andClearances

This article should only be used as a guide. It¶s intended purpose is to help the piping designer

who is responsible for placement of one specific item in a typical refinery, chemical or petrochemical process plant or someone who may need help in developing a total plot plan for a

complex unit.The guidelines given here are based on my many years of experience with one of the world¶s

largest engineering, design and construction companies along with the U. S. OSHA Part 1910and the NFPA (National Fire Protection Association) Code No. 30.

The latest editions of these codes and any other applicable national, regional and local codesshould be referred to and used because they may be more stringent.

The subjects covered in this article have been arranged in alphabetical order in the hope it willmake them easier to locate.

Access (See Maintenance) Columns (See Vertical Vessels) Compressors, Centrifugal Locate centrifugal compressor as close as possible the suction source. Top suction and discharge

lines either should be routed to provide clearance for overhead maintenance requirements, or should be made up with removable spool pieces.



Support piping so as to minimize dead load on compressor nozzles; the load should be within therecommended allowance of the compressor manufacturer.

Centrifugal compressors should have full platforming at operating level. Heavy parts such asupper or inner casing and rotor should be accessible to mobile equipment. Review the equipment

arrangement for access and operation.

Locate lube and seal oil consoles adjacent to and as close as possible to the compressor. Oilreturn lines from the compressor and driver should have a minimum slope of 1/2 inch per foot tothe inlet connection of seal traps, degassing tanks, and oil reservoir. Pipe the reservoir,

compressor bearing, and seal oil vents to a safe location at least 6 feet above operator head level.Compressors, R eciprocating

Locate reciprocating compressors so suction and discharge lines that are subject to vibration(mechanical and acoustical) may be routed at grade and held down at points established by a

stress and analog study of the system.Accessibility and maintenance for large lifts such as cylinder, motor rotor, and piston removal

should be by mobile equipment if the installation is outdoors or by traveling overhead crane if the installation is indoors (or covered).

Horizontal, straight line, reciprocating compressors should have access to cylinder valves.Access should be from grade or platform if required.

Depending on unit size and installation height, horizontal-opposed and gas engine drivenreciprocating compressors may require full platforming at the operating level.

Control Valves Locate control valve stations accessible from grade or on a platform. In general, the (flow, level,

pressure, temperature) instruments or indicators showing the process variables should be visiblefrom the control valve.

Cooling Towers Locate cooling towers downwind of buildings and equipment to keep spray from falling on them.

Orient the short side of the tower into the prevailing summer wind for maximum efficiency. Thismeans that the air flow (wind) will travel up the long sides and be drawn in to both sides of the

cooling tower equally. When the wind is allowed to blow directly into one long side it tends to blow straight through and results in lower efficiency. Locate cooling towers a minimum of 100

feet (30m) from process units, utility units, fired equipment, and process equipment.Cradles (See Insulation Shoes and Cradles)

Equipment Arrangement (General) Arrange equipment, structures, and piping to permit maintenance and service by means of

mobile equipment. Provide permanent facilities where maintenance by mobile equipment isimpractical.

Group offsite equipment, pumps, and exchangers to permit economical pipe routing. Locate thisequipment outside of diked storage areas.

Exchanger, Air Cooler (Fin Fans) Air Coolers are in typically used in the cooling of the overhead vapor from tall vertical vessels or

towers such as Crude Fractionators and Stripper Columns. The natural flow tends to followgravity, where the tower overhead is the high point then down to the Air Cooler, then down to

the Accumulator and finally the Overhead Product transfer pumps. With this in mind the Air Coolers are normally located above pipeways. This conserves plot space and allows the pipe rack

structure with it¶s foundation to do double duty with only minor up grade to the design. If the



pipe rack is not used then plot space equal to the size of the Air Cooler is required. In addition atotally separate foundation and stand alone structure is required.

Exchanger, ³G´ Fin (Double Pipe) These exchangers can be mounted almost anywhere any they can be mounted (with process

engineer approval) in the vertical when required. A G-Fin Exchanger is recognizable by its

shape. One segment looks like two long pieces of pipe with a 180 degree return bend at the far end. It is one finned pipe inside of another pipe with two movable supports. This type of exchanger can be joined together very simply to form multiples in series, in parallel or in a

combination of series/parallel to meet the requirements of the process. This exchanger is notnormally used in a service where there is a large flow rate or where high heat transfer is required.

The key feature with this exchanger is the maintenance. The piping is disconnected from the tubeside (inner pipe). On the return bend end of this exchanger there is a removable cover. When the

cover is removed this allows for the tube (inside pipe) to be pulled out. This exchanger isnormally installed with the piping connections toward the pipe rack.

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Piping-Location-Spacing-Distances-and-Clearanc#ixzz1klLdJuHB Exchangers, R eboiler (Kettle R eboiler) Locate kettle reboilers at grade and as close as possible to the vessel they serve. This type of reboiler is identifiable by its unique shape. It has one end much like a normal Shell and Tube

exchanger then a very large eccentric, bottom flat transition to what looks like a normalhorizontal vessel. You could also call it a ³Fat´ exchanger. The flow characteristics on the

process side of a kettle reboiler are the reason for the requirement for the close relationship to therelated vessel.

Reboilers normally have a removable tube bundle and should have maintenance clearance equalto the bundle length plus 5 feet (1.5m) measured from the tube sheet.

Exchangers, Shell and Tube Shell and tube exchangers should be grouped together wherever possible. Stacked shell and tube

exchangers should be limited to four shells high in similar service; however, the top exchanger should not exceed a centerline elevation of 18 feet (5.5m) above high point of finished surface,

unless mounted in a structure. Keep channel end and shell covers clear of obstructions such as piping and structural members to allow unbolting of exchanger flanges, and removal of heads

and tube bundles.Exchangers with removable tube bundles should have maintenance clearance equal to the bundle

length plus 5 feet (1.5m) measured from the tube sheet to allow for the tube bundle and the tube puller.

Maintenance space between flanges of exchangers or other equipment arranged in pairs should be 1- 6 (0.5m) (min.). Exchanger maintenance space from a structural member or pipe should

not be less than 1- 0 (300mm) (min.).

Furnaces (Fired Equipment) Locate fired equipment, if practical, so that flammable gases from hydrocarbon and other processing areas cannot be blown into the open flames by prevailing winds.

Horizontal clearance from hydrocarbon equipment (shell to shell) 50- 0 (15m) Exception: Reactors or equipment in alloy systems should be located for economical piping arrangement.

Provide sufficient access and clearance at fired equipment for removal of tubes, soot blowers, air preheater baskets, burners, fans, and other related serviceable equipment.



Clearance from edge of roads to shell 10- 0(3m)Pressure relief doors and tube access doors should be free from obstructions. Orient pressure

relief doors so as not to blow into adjacent equipment.The elevation of the bottom of the heater above the high point of the finished surface should

allow free passage for operation and maintenance.

Furnace Piping Locate snuffing steam manifolds and fuel gas shutoff valves a minimum of 50 feet (15m)horizontally from the heaters they protect.

Burner Valving for a Floor Fired Furnaces: Combination oil and gas firing valves should beoperable from burner observation door platform. For those fired by gas only, the valves should

be near the burner and should be operable from grade.Burner Valving for a Side Fired Furnaces: Locate firing valves so they can be operated while the

flame is viewed from the observation door.Flare Stacks

Locate the flare stack upwind of process units, with a minimum distance of 200 feet (60m) from process equipment, tanks, and cooling towers. If the stack height is less than 75 feet (25m),

increase this distance to a minimum of 300 feet (90m). These minimum distances should beverified by Company Process Engineering.

Future Provisions Space for future equipment, pipe, or units should not be provided unless required by the client or

for specific process considerations. When applicable this requirement should be indicated on the plot plan and P&IDs.

Insulation Shoes and Cradles Locate Insulation shoes anywhere a line crosses a support for hot insulated piping when the

piping is 3 inch (80mm) and larger carbon and alloy steel lines with design temperatures over 650 degrees F (350C).

Large diameter lines (20 inches (500mm) and over), stainless steel lines where galvaniccorrosion may exist, lines with wall thickness less than standard weight, and vacuum lines should

be analyzed to determine if shoes or wear plates are needed.Provide cradles at supports for insulated lines in cold service and for acoustical applications.

Ladders & Cages Maximum height of a ladder without a cage should not exceed 15-0 (4.5m)

Maximum vertical distance between platforms 30- 0 (9m)Cages on ladders over 15-0 (4.5m) high shall start at 8-0 (2.5m) above grade.

Minimum toe clearance behind a ladder 0- 7 (200mm)Minimum handrail clearance 0- 3 (80mm)

Level Instruments Locate liquid level controllers and level glasses so as to be accessible from grade, platform, or

permanent ladder. The level glass should be readable from grade wherever practical.Wherever possible, orient level instruments on the side toward the operating aisle.

Loading R acks Locate loading and unloading facilities that handle flammable commodities a minimum of 200

feet (60m) from away from process equipment, and 250 feet (75m) from tankage.Maintenance Aisles (at grade) Equipment maintenance aisle for hydraulic crane (12T capacity) should have a horizontalclearance width of 10- 0 (3m) (min.) and a vertical clearance of 12- 0 (3.5m) (min.). Where a



fork lift and similar equipment (5000 lbs / 230kg capability) is to be used the horizontalclearance should be 6- 0 (2m) (min.) and the vertical clearance should be 8- 0 (2.5m) (min.).

Where maintenance by portable manual equipment (A-frames, hand trucks, dollies, portableladders or similar equipment) is required the horizontal clearance should be 3- 0 (1m) (min.)

and the vertical clearance 8- 0 (2.5m) (min.).

Operating Aisle (at grade) Minimum width 2- 6 (800mm)Headroom 7- 0 (2.1m)

Orifice R uns and Flanges Locate Orifice runs in the horizontal. Vertical orifice runs may only be used with the approval of

Company Control Systems Engineering. Orifice flanges with a centerline elevation over 15 feet(4.5m) above the high point of finished surface, except in pipeways, should be accessible from a

platform or permanent ladder.Locate orifice taps as follows:

Air and Gas-Top vertical centerline (preferred)

-45 degrees above horizontal centerline (alternate)]Liquid and Steam

-Horizontal centerline (preferred)-45 degrees below horizontal centerline (alternate]

(Note: The piping isometrics should show the required tap orientations)Personnel Protection

Locate eye wash and emergency showers in all areas where operating personnel are subject tohazardous sprays or spills, such as acid.

Personnel protection should be provided at uninsulated lines and for equipment operating above140 degrees F (60 C) when they constitute a hazard to the operators during the normal operating

routine. Lines that are infrequently used, such as snuffing steam and relief valve discharges, maynot require protective shields or coverings.

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Piping-Location-Spacing-Distances-and-Clearanc#ixzz1klLhdOwi Pipe

Clearance between the outside diameter of flange and the outside diameter of pipe to theinsulation should not be less than 0- 1* (25mm)

Clearance between the outside diameter of pipe, flange, or insulation and structural any member should not be less than 0- 2* (50mm)

*With full consideration of thermal movements

Platforms Minimum width for ladder to ladder travel: 2- 6 (800mm)

Headroom: 7- 0 (2.1m)Headroom from stairwell treads: 7- 0 (2.1m)

Minimum clearance around any obstruction on dead end platforms: 1- 6 (500mm)Pressure InstrumentsLocate all local pressure indicators so they are visible from grade, permanent ladder, or platform.Those located less than 15 feet (4.5m) above high point of finished surface should be accessible



from grade or a portable ladder. Those located in a pipeway should be considered accessible by portable ladder. Those over 15 feet (4.5m) above high point of finished surface should be

accessible from a platform or permanent ladder.Process Units The relation of units, location of equipment, and routing of pipe should be based on economics,

safety, and ease of maintenance, operation, and construction requirements. The alignment of equipment and routing of pipe should offer an organized appearance.Process Unit Piping

Locate all pipe lines in major process units on overhead pipeways. In certain instances, pipesmay be buried, providing they are adequately protected. Lines that must be run below grade, and

must be periodically inspected or replaced, should be identified on the P&IDs and placed incovered concrete trenches.

Cooling water lines normally may be run above or below ground, based on economics.Domestic or potable water and fire water lines should be run underground.

Pumps Locate pumps close to the equipment from which they take suction. Normally, locate pumps in

process units under pipeways.Design piping to provide clearance for pump or driver removal. Similarly, on end suction pumps,

piping should permit removing suction cover and pump impeller while the suction and dischargevalves are in place.

Arrange suction lines to minimize offsets. The suction lines should be short and as direct as possible, and should step down from the equipment to the pump. Suction lines routed on

sleeperways may rise to pump suction nozzle elevation.Orient valve handwheels or handles so they will not interfere with pump maintenance or motor

removal. Valve handwheels or handles should be readily operable from grade.Maintenance and operating aisles with a minimum width of 2-6 (800mm) should be provided

on three sides of all pumps.Pump Strainers

Provide temporary conical type strainers in 2 inch (50mm) and larger butt weld pump suctionlines for use during startup. Arrange piping to facilitate removal.

Use permanent Y-type strainers on 2 inch (50mm) and smaller screwed or socket weld pumpsuction piping.

R ailroads Headroom over through-railroads (from top rail) 22- 6** (7m)

Clearance from track centerline to obstruction 10- 0** (3m)(** Verify conformance with local regulations)

R elief Valves (Pressure, Safety and Thermal)Locate all relief valves so they are accessible. Wherever feasible, locate them at platforms that

are designed for other purposes. Relief valves with a centerline elevation over 15 feet (4.5m)above high point of finish surface (except in pipeways) should be accessible from platform or

permanent ladder.Pressure relief valves that discharge to a closed system should be installed higher than the

collection header. There should be no pockets in the discharge line.Safety relief valves (in services such as steam, etc.) that discharge to the atmosphere should have

tail pipes extended to a minimum of 8 feet (2.5m)above the nearest operating platform that iswithin a radius of 25 feet (7.5m). This requirement may be waived, provided a review of the



proposed arrangement indicates that it does not present a hazard. Review all pressure and safetyrelief valves discharging flammable vapors to the atmosphere within 100 feet (30m) of fired

equipment for vapor dissipation.Pressure and Safety relief valves, 1-1/2 inch (40mm) and larger, should only be installed with the

stem and body vertical position.

Thermal relief valves, 1 inch (25mm) and smaller, may be installed with the stem and body in ahorizontal position when it is impractical to install it in the vertical position.R oads

Major process plants normally have three classes of roads. They might be called Primary roads,Secondary roads and Maintenance access ways.

Clearance or distance required R oad type Vertical Width Shoulder Side or off road Primary 21-0 (6.5m) 20-0 (6m) 5-0

(1.5m) 20-0 (6m) Secondary (*) 12-0 (3.7m) 12-0 3.7m) 3-0 (1m) 10-0 (3m)Maintenance access 10-0 (3m) 10-0 (3m) (not req¶d) 5-0 (1.5m)

(*) Normally secondary plant roads may be used as tube pull areas.

Safety Access Provide a primary means of egress (continuous and unobstructed way of exit travel) from any

point in any building, elevated equipment, or structure. A secondary means of escape should be provided where the travel distance from the furthest point on a platform to an exit exceeds 75

feet (25m).Access to elevated platforms should be by permanent ladder. Safety cages should be provided on

all ladders over 15-0 (4.5m)The need for stairways should be determined by platform elevation, number of items requiring

attention, observation and adjustment, and the frequency of items.Ladder safety devices such as cable reel safety belts and harnesses, may be investigated for use

on boiler, flare stack, water tank, and chimney ladders over 20 feet (6m) in unbroken lengths inlieu of cage protection and landing platforms.

Sample Connections Locate all sample connections so they are readily accessible from grade or platform.

In general, where liquid samples are taken in a bottle, locate the sample outlet above a drainfunnel to permit free running of the liquid before sampling.

Hot samples should be provided with a cooler.Sleeper Pipe Supports

Normally, route piping in offsite areas on sleepers. Stagger the sleeper elevations to permit easeof crossing or change of direction at intersections. Flat turns may be used when entire sleeper

ways change direction.Spectacle Blinds

Locate spectacle blinds to be accessible from grade or platform. Blinds located in a pipeway areconsidered accessible. Blinds that weigh over 100 lbs (45kg) should be accessible by mobile

equipment. Where this is not possible, provide davits or hitching points.Closely grouped flanges with blinds should be staggered.

Steam Traps Locate all steam traps at all pocketed low points and at dead ends of steam headers. Also,

provide traps periodically on excessively long runs of steam piping, for sufficient condensateremoval, and to ensure dry quality steam at destination. Steam traps should be accessible from



grade or a platform. Steam traps located in pipeways should be considered accessible by portableladder.

Tankage Locate any tankage containing hydrocarbon or other combustible fluids or gasses a minimum

distance of 250-0 (115m) from any process unit, rail loading facility or truck loading facility.

The minimum spacing of offsite storage tanks and dike requirements should be in accordancewith the latest edition of the National Fire Protection Association, Code No. 30, and OSHA part1910.106 (b), where applicable.

Temperature InstrumentsLocate temperature test wells, temperature Indicators and thermocouples to be accessible from

grade or a portable ladder. Those located in a pipeway should be considered accessible by a portable ladder. Those located over 15 feet (7m) above high point of finished surface should be

accessible from a platform or permanent ladder.Locate all local temperature indicators (TI) should be visible from grade, ladder, or platform.

Towers (See Vertical Vessel)Utility Stations

Provide and locate utility stations with water, steam, or air as indicated below:All areas should be reachable with a single 50 foot (20m) length of hose from the station.

Provide water outlets at grade level only, in pump areas, and near equipment that should be water washed during maintenance.

Provide steam outlets at grade level only in areas subject to product spills, and near equipmentthat requires steaming out during maintenance.

Provide air outlets in areas where air-driven tools are used such as at exchangers, both ends of heaters, compressor area, top platform of reactors, and on columns at each manway.

Hose, hose rack, and hose connections should be provided by the client or be purchased to matchthe clients existing hardware.

Valve Handwheel Clearance Clearance between the outside of hand wheel and any obstruction (knuckle clearance) should be

0- 3 (80mm)Valve Operation

Locate operating valves requiring attention, observation, or adjustment during normal plantoperation (noted on the P&IDs) so they may be within easy reach from grade, platform, or

permanent ladder as follows:- 2 (50mm) and smaller may be located reachable from a ladder.

- 3 (80mm) and larger must be reachable and operable on a platformOperating valves with the bottom of handwheel is over 7 feet (2.1m)above high point of finished

surface or operating platform may be chain-operated.The centerline of handwheel or handles on block valves used for shutdown only, located less

than 15 feet (4.5m) above high point of finished surface, and those located in pipeways, may beaccessible by portable ladder.

The centerline of handwheel or handles on block valves used for shutdown only and located over 15 feet (4.5m) above high point of finished surface, except those located in pipeways, should be

operable from permanent ladder or platform.In general, keep valve handwheels, handles, and stems out of operating aisles. Where this is not

practical, elevate the valve to 6- 6 (plus or minus 3 inches) clear from high point of finishedsurface to bottom of handwheel.



Vents and Drains The P&IDs should indicate, locate and size all vents, drains, and bleeds required for process

reasons and plant operation.Provide plugged hydrostatic vents and drains without valves at the high and low points of piping.

Provide valved bleeds at control valve stations, level switches, level controllers, and gage glasses

per job standard.Vertical Vessel (Column) Piping and Platforms Locate vertical vessels in the equipment rows on each side of the pipeway in a logical order

based on the process and cost. The largest vessel in each equipment row should be used to set thecenterline location of all vertical vessels in that equipment row. This largest vertical vessel

should be set back from the pipe rack a distance that allows for; any pumps, the pump piping, anoperation aisle between the pump piping and any piping in front of the vessel, the edge of the

vessel foundation and half the diameter of this the largest vessel. Set all other vertical vessels inthis same equipment row on the same centerline.

Provide a clear access area at grade for vessels with removable internals or for vessels requiringloading and unloading of catalyst or packing.

Provide vessel davits for handling items such as internals and relief valves on vessels exceedinga height of 30 feet (9m) above the high point of the finished surface, and on vessels not

accessible by mobile crane. Orient davits to allow the lowering of appurtenances into the accessarea.

Walkways Walkways should have a 2-6 (1m) horizontal clearance (not necessarily in a straight

line) and headroom of 7- 0 (2.1m)

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PIPEWORK

4.2. PIPEWORK

4.2.1 Applications

Pipework is extensively used throughout an offshore installation to move fluids and gases from one

location to another. It can generally be classified into the following three broad groupings:

4.2.1.1 Process

Used to transport the produced fluids and gases between processing units on the platform.

4.2.1.2 Service

Used to convey air, water, etc. to where it is needed for processing, life support and other services or

utility functions.



4.2.1.3 Transportation

Usually large diameter pipelines as used to carry the production products from installation to

installation or from the field to the onshore terminal.

Pumps and compressors are used to drive fluids and gases along pipes and valves to route and control

the various substances and ensure that they are correctly segregated from each other.

The contents of the pipework are carried at widely varying temperatures, pressures and flow rates

and,therefore, different types of pipework and associated equipment are required.

Because of the inherent danger in carrying the oil and gas associated with offshore operations, the

design,installation, testing and inspection of certain pipework is ngourously controlled to exacting

standards, so that leakage and bursting do not occur.

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4.2.2 Design Features

4.2.2.1 Pipe Materials

Pipes are made in a number of materials, the particular one chosen being dependent upon

pressure,temperature, resistance to corrosion, cost etc.

The most commonly used is carbon steel and for process work, this is normally of seamless construction.

It is strong, weldable, ductile, and usually cheaper than pipe made from other materials. It can stand

temperatures up to 750ºF and is used whenever it can stand the duty required of it.

Other metals and alloys are sometimes used although they tend to be more expensive. Traditionally,

corer and copper alloys were used for instrument lines although they have largely been replaced by

stainless steel. They are still used for heat transfer equipment because of their high thermal

conductivity.

Pipe can be lined or coated with materials such as vitreous substances, to provide resistance to chemical

attack, corrosion, etc.

GRP (Glass Reinforced Plastic) is commonly used offshore on smaller service/potable water lines.

4.2.2.2 Pipe Sizes



The wall thickness of pipe used is determined by the pipework designer, taking into account the internal

pressure, mechanical stresses to which it is subjected (i.e. dead/live loads and expansion stresses), the

corrosion allowance and the safety factor to be applied. Wall thickness is determined in the ANSI system

by Schedule Number, Schedule 40 being the most generally used.

Pipe size is determined by the design requirements of flow rate and head loss. Pipe sizes are identified

by the Nominal Pipe Size (NPS). It is common practice to refer to Nominal Pipe Sizes 0-12 inches

diameter as Nominal Bore (NB) and greater than 12 inches diameter as Outside Diameter (OD).

4.2.2.3Methods of Joining Pipe

There are three main methods of joining pipes together and attaching fittings to them. Lines of 2 inch or

larger are usually butt-welded, this being the most economic, leak-proof method. Smaller lines are

usually joined by socket-welding or screwing.

Where larger diameter piping is required to join up with flanged vessels, valves and other equipment, orwhere the line has to be opened for periodic cleaning, bolted flange joints are used instead of butt-

welding.

These are described more fully later.

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4.2.3 Butt-Welded Systems Fittings

Elbows: These are used for making 45º or 90º changes in the direction of the pipe run.

Normally used are long radius, in which the centre line radius of

curvature is equal to 1 1/2 times the nominal pipe size (MPS). Also available are short radius in which

the centre line radius of curvature is equal to the NIS.

4.2.3.1 Reducing Elbow



This makes a change in line size together with a change in direction.

4.2.3.2 Return

A return makes a 180 change in direction and is used in the construction of heating coils, etc.

4.2.3.3 Bends

Bends are made from straight pipe and common bending radii are 3 and 5 times the NIS (indicated by

3R and SR respectively).

4.2.3.4 Reducer



This joins a larger pipe to a smaller one.

4.2.3.5 Flange

REFER THIS ALSO

Is a welding-neck flange (the most common type) and a slip-on flange. Flanges are fitted to the ends of

pipes, valves, vessels, etc. to enable them to be connected by bolting.

4.2.3.6 Tee

REFER THIS ALSO



A tee is used to make a 90 branch from a main pipe run. If the branch is smaller than the main run, a

reducing tee is used.

4.2.4 Socket-Welded and Screwed Systems



Their uses are similar to those described for butt-welded fittings.



4.2.5 Flanged Joints

As described earlier, flanged joints are used whenever the pipes, valves, vessels, fittings etc. require to

be connected together by bolting for ease of dismantling and reassembly.

This section describes types of flanged joints, which are commonly encountered.

4.2.5.1 Flat-Face



Most commonly used for mating with non-steel flanges on the bodies of pumps, valves, etc. The gaskets

used (see Gaskets below) have an outside diameter equal to that of the flange itself. This ensures an

even pressure distribution across the flange and reduces the risk of -----ing of cast-iron or bronze flange

on tightening or from plant vibration.

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4.2.5.2 Raised Face

The raised face is the most common type of flange, in which the gasket covers only the raised faces.

4.2.5.3 Ring-Type Joint (RTJ)

This is a more expensive type of joint, but it is the best type for high temperature, high pressure and

corrosive use

4.2.5.4 Gaskets

Gaskets are used to make a tight leak-proof seal between two joint surfaces. For pipe flanges, the



common types of gaskets are the full-face and ring types which are used for flat-face and raised-face

flanges respectively.

Gaskets are made from compressed asbestos, asbestos-filled metal (spiral-wound) and other materialsdependent on the conditions to which they are subjected. Spiral-wound gaskets separate cleanly and

can often be re-used.

They are useful, therefore, if the joint has to be frequently disconnected. The finish on the joint faces

differs according to the type of gasket to be used. A serrated face is used with asbestos gaskets and a

smooth face with spiral-wound ones.

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4.2.5.5 Line Isolation and Blinding



Frequently, a completely leak-proof means of stopping the flow in a line has to be made. This may be

because:

The line, or a piece of equipment in it, has to be isolated to allow maintenance work to be carried out;

A change in the process requires that the line be closed.

Valves do not offer complete security, as there may always be some degree of leakage and therefore,

the line is closed by one of the following methods:

Spectacle Plate and Line Blind: The spectacle plate can be changed over quickly without disturbing the

pipework and gives immediate visual evidence of whether the line is open or blinded. it is generally

preferable to the simple line blind which is only used where frequent changing is not required.

Line Blind Valve: This allows a line to be quickly and simply blinded by a process operator. There aremany types, but a typical one, a spool type line blind.

Removable Spool and Blind Flanges: This method involves removing a complete section of the line

between two flanges (the spool) and fitting blind flanges to close the two ends of the line. This gives a

very positive visual indication that the line is closed. Blind flanges are used to close any pipe end, vessel

entry, etc.



4.2.5.6 Pipe Supports

Methods of supporting pipework vary greatly, but a selection of some of the more common is covered in

this section.

Support: The term support refers to any device used to carry the weight of the pipework. Supports are

usually made from structural steel.

Hanger: A hanger is a particular type of support by which pipework is suspended from a structure.

Hangers are usually adjustable for height

Anchor: An anchor is a rigid support, which prevents transmission of movement along pipework.

Tie: An arrangement of rods, bars, etc. to restrict movement of pipework.

Dummy Leg: An extension piece of pipe or steel section welded to an elbow.

Guide or Shoe: A means of allowing a pipe to move along its length whilst restricting its lateral

movements.



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4.2.6 Operation

4.2.6.1 Checks During Operation

The operation of a piping system is dictated by the operation of the equipment, which it connects.

Nevertheless, care must be taken at all times to ensure that

The piping is not operated beyond its design range of pressure and temperature;

All joints are checked regularly for leaks and any leaks discovered are reported immediately;

The piping is correctly isolated and purged, if necessary, before any maintenance work is performed

on it;

Line markings are clearly visible and re-made if not;

Any abnormal vibration, damage, missing supports, etc are reported immediately.

4.2.6.2Maintenance and Inspection

Legislative and other statutory requirements dictate the type and frequency of maintenance and

inspection required on piping systems installed on offshore Installations. This maintenance and

inspection is necessary to ensure that the Certificate of Fitness of the installation in question remainsvalid. The responsibility for ensuring that these requirements are met does not lie with the process

operator.

However, he will be involved in isolating. purging, etc. at the time the maintenance and inspection are

carried out.

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