Sizing Of Pipelines

SIZING OF PIPELINES

Oil Pipelines
Pumping a specified quantity of a given oil over a given distance may be achieved by using a large 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 to strike 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 provision of 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 the number 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.

Gas Pipelines
Sizing problems encountered in gas lines differ considerably from those of oil lines. A simplification 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 the complication 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 pressure decreases 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 and velocity of the gas are at optimum conditions.

Pipeline Pigging

Pipeline Pigging

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 pig usually 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 brushes and 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 “Go-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 (“intelligent-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 required depends 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 a crude 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 is relatively constant.

Pigging Operations

Pigs are used in all types of pipelines to increase efficiency and avoid problems at pump or compressor stations that could result from the presence of unwanted materials. Brushes and scrapers on a cleaning pig remove dirt and scale from the pipeline walls. Brush and scraper pigs feature longitudinal boles, which pass through the body of the pig. The holes allow a flow of fluid through the pig to prevent the build-up of wax or debris in front of the pig.

A pig can remove very large amounts of debris if it is run over a long distance.

For example, assume a pig is run in a 24 in. pipeline, 100 miles long, and removes 0.016 in. of wax material from the wall of the pipeline. After 100 miles, a plug about 1,450 ft long would form. For this reason, pipelines are operated to very definite pigging programmes.Pipelines are often pigged first during testing following construction. Most pipelines are tested with water (hydrostatic testing) either in sections or over the entire length. A foam pig or pigs is normally sent ahead of the water when filling the test section to prevent mixing the test water with air in the line. Internallycoated pipelines are often flushed with water ahead of a pig to prevent debris from being dragged along the inside surface, damaging the coating.

After testing, the water is usually displaced with the fluid to be transported in the pipeline. A pig is run between the two fluids to separate them. In gas pipelines, the pig is used to “dewater” the pipeline by running it behind the test water. Additional pigs may also be run to ensure that as much moisture as possible is removed from the line.

Launching And Receiving

Equipment is required to introduce the pig into the pipeline and to retrieve the pig at the end of the segment being pigged. A launcher is required at the upstream of the section and a receiver at the down-stream end.

The distance between these pig “traps” depends on service, location of pump or compressor stations, operating procedures and the material used in the pig.

The design of pig launchers, pig traps and related equipment is done in accordance with standards developed by several organisations. Traps for brush pigs, squeegees and foam pigs include a barrel, short pup joint, a trap valve, a side valve and a bypass line. The barrel holds the pig for loading and unloading and is equipped with a quick-opening closure or blind flange. A barrel diameter larger than the diameter of the pipeline served is required in order to allow the Pig to be successfully launched or retrieved. Barrel length depends on operating procedures, service and available space.

Figure 4.30 and Figure 4.31 illustrate a pig launcher and a pig receiver respectively.

Sphere launchers are often designed for multiple sphere launching and recovery duties and the barrels for sphere launchers are typically longer than those for other types of pigs. The operator can load these magazines with several spheres that can be launched automatically. This approach is often used in two-phase pipelines where the barrels may be designed to accommodate over lo spheres. The sphere launcher consists of the barrel, a launching mechanism, an isolation valve, an equaliser valve and a reducing tee. A drain can serve as an equalizing line.

Figure 4.32 illustrates a sphere launcher/receiver system

Figure 4.34, shows a sphere being filled with antifreeze solution.

Combination pig and sphere launchers can also be designed if both cleaning pigs and spheres for liquid control are needed.

Pig Launching And Receiving Procedures

Pig launching and receiving procedures are often supervised by senior operations staff and fully monitored by all pipeline users but the actual procedures laid down for each pig launching/pig receiving facility will vary.

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 normal operating 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 “interlock-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 final stages. 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, not always reliable.

The pig is launched successfully but fails to arrive on time with no major changes in pipeline pressures or flows. The possible causes are:
1. The pig is too small (wrong size) and cannot climb the riser into the receiver.

2. The pig has disintegrated into its component parts.

3. The pig is hung on a bend and the cups have “flipped” forwards to allow full flow.

The pig is launched successfully but fails to arrive on time and there is an increase in pipeline pressure drop in pipeline flow.

The possible causes are:

1. The pig has hung up on a bend or ’T ’piece (pig is too long for bend radius).

2. The wrong size of pig was launched (too large in diameter).

3. The pipeline has been dented and the pig is stuck at the damaged section.

The pigs “leap-frog” each other in the pipeline; (usually foam pigs).

The possible causes are:

1. The operator launched them 1, 3, 2 but did not realise (most common);

2. The front pig hangs up on an obstruction and is only cleared by the second pig rolling over it.

Spheres arrive with huge chunks missing. The most likely cause is that the launcher valve has taken a bite out of the sphere as it was launched.

Launcher valves are often half-cup ball valves, which rotate through 180º to launch the sphere. Oversized spheres hang over the side of the cup and are sliced as the cup rotates.

Pigs and spheres go into by-pass lines, junction ‘T pieces or other pipelines. Operator error or process upsets may often create situations where the sphere or pig can deviate from its normal path. In one known instance a 28” diameter neoprene sphere travelled into a 12” diameter pipe for some considerable distance before flow was stopped.

Whatever the “Causes” of pigging problems, the “effects” can be severe and in some instances the pipeline has had to be cut out to remove the offending pig.

Pumps

Lesson 1 — ABOUT PUMPS

Lesson Introduction
All pumps are broadly classified into two general categories: kinetic and positive-displacement. Within these categories, there are six common classes of pumps.

In this lesson, the six classes of pumps are described and identified according to the method used to create pressure. Within each class, in turn, are several types of pumps that vary from each other by their pumping method, and consequently their operating technique. For you to work safely and efficiently in a facility, you must know about the pumps your facility uses and how they operate.

In this lesson, you will learn the categories, classes, and types of pumps. You will also learn the functions of each of the common classes of pumps.

Categories of Pumps
Pumps can be broadly classified into two categories: kinetic pumps and positive-displacement pumps.

Kinetic Pumps
A kinetic pump builds pressure by first creating high fluid velocity with a rotating element. Then the fluid velocity is converted to pressure by the shape of the discharge passage. Because the fluid1 in a kinetic pump is always free to spin unrestricted within the pump casing, the discharge may be restricted or blocked without building up excessive pressure.

Positive-displacement Pumps
A positive-displacement pump is one in which a trapped amount of liquid is forced (or displaced) from the pump as the pumping mechanism moves. In theory, pressure is limited only by the power available to move the pumping element. In practice, if the discharge of a positive displacement pump is blocked, either the pump driver will stall, or the pump will rupture to relieve the pressure

NOTE
In general practice, a relief valve is installed on the discharge of a positive-displacement pump to protect against over pressure if the discharge becomes restricted or blocked. The relief valve outlet is usually routed back into the suction line. It is a dangerous practice to intentionally block the discharge valve of a positive-displacement pump and depend on the relief valve to relieve the pressure.
1 A substance that conforms to the outline of its container and has a tendency to flow. Liquids, gases, and vapors are fluids.
2 The measure of a liquid’s force per unit area.

Six Common Classes of Pumps
There are six common classes of pumps used in the process industry:
• Centrifugal
• Axial flow
• Turbine propeller
• Reciprocating
• Rotary
• Metering

The first three classes are categorized as kinetic pumps, while the last three are positive-displacement pumps. Each of the six classes applies different methods to create pressure, and these differences significantly affect pump operation.