Virtual Pipeline

Hydraulic Surges

HYDRAULIC SURGE,

or "Water Hammer"

 BACKGROUND

Surge predictions in oil and hydrocarbon pipelines have been developed from the long established methods used in the water works industries, but the petroleum and water lines have complicated differences.  Oil and hydrocarbon pipelines, unlike most water lines, can be very long, are constructed of high strength ductile steel and exhibit high frictional losses due to their long lengths.  Petroleum products, relative to water, are less dense, more viscous and have higher vapor pressures, thus at times low pressure operation may not be appropriate.  The inherent surge dampeners of the oil and hydrocarbon pipelines prohibit the direct application of water hammer analysis to hydraulic shock in these pipelines.

Surge pressure in a 25 mile long 16” diameter pipeline, flowing 200,000 bbl/day of diesel can be as high as 400 psi and surges originating at the beginning of the pipeline will reach the end terminal in about 42 seconds.

It is not only the initial increased surge pressure that must be safely handled.  Reflected pressure waves can also be significant.  Additionally,  the pipeline’s configuration must be considered.  Should the same 25 mile long pipeline of the previous example be constructed using 16” pipe for the first 12.5 miles and 12” pipe for the second 12.5 miles, any transient wave originating at the beginning of the pipeline will be partially reflected back to the pump station from the pipe diameter junction point and a portion of the original wave will continue to the terminal.

If the last 12” diameter segment of the preceding example were to be looped with another pipeline, any transient wave will be partially reflected back to the pump station from the junction and the original wave will be divided and amongst each of the looped pipelines, in portion to the respective areas divided by the respective wave velocities of each segment, as the original wave continues on to the terminal.

In dead or closed ends, the pressure wave is reflected back with the same algebraic sign, while in opened end situations, the wave is reflected with opposite algebraic sign.

Tripping a pump or an entire pump station will cause the fluid flow to slow or to come to a complete stop that can cause large transient pressure waves to be created.  Stopping flow causes the suction pressure to build up and the discharge pressure to decrease until flow is re-established.  Suction pressure will build to ΔP_pump * Discharge_Area/(Suction_Area + Discharge_Area)  and discharge pressure will build to ΔP_pump * Suction_Area/(Suction_Area + Discharge_Area).

 In the pump trip example, if the flow has not re-established itself before reflections arrive, significant combined wave amplitudes can be experienced.

A pump station start-up with an open discharge valve will generate a flow surge and accompanying pressure transient wave, due to the sudden flow increase.  As the pipeline resistance increases due to an ever increasing flow, the flowrate increase over time is reduced until the steady state operating point flowrate is achieved.  The transient pressure wave will travel down the pipeline until it is reflected back to the pump station, each time increasing flow and pressure in the pipe until finally, the pump discharge pressure intersects the pipeline’s operating flowrate system curve and stable flow is achieved.  The same type of wave phenomenon occurs on the suction side of the pump however, pressure decreases until the pump suction head and feeding pipeline’s system curves intersect at the pump’s operating suction pressure.

Large amplitude combined transient pressures can also be generated due to the fast closure rates of Emergency Shut-Down (ESD) valves and relief valves lifting to prevent overpressures when high transient pressures occur.  At times waves can add together creating total pressure amplitudes in excess of those created solely by individual activation of a given component.  If pipeline flow velocities are high, momentum of the moving fluid flowing into the valve and hitting the closed surface will cause the fluid to compress against the valve on the upstream side and to move away from the closed valve face on the downstream side.  The upstream compression can be accompanied by high pressures, while the downstream side may experience near vacuum conditions.  As the fluid finally slows, it will tend to reverse direction and eventually arrive at a stable pressure when motion completely stops.

Transient pressures can be created due to moving in or out of slack flow conditions.  Slack flow conditions occur when pipeline pressures at some point, usually at the highest point of a pipeline, reduce to levels below the bubble point or vapor pressure of the liquid being transported.  Essentially a pipeline liquid in this condition flows in the open channel flow regime, with a gas pocket above its surface with a pressure equal to the liquid’s vapor pressure.  If pipeline pressure reduce below the vapor pressure of the liquid allowing the gas pocket to form, or when pipeline pressures increase and pass through and above the vapor pressure, very high transient pressure waves can be created, especially when widely separated columns of liquid collide as the vapor pocket implodes and vanishes.

WHEN IS IT RECOMMENDED TO DO A TRANSIENT ANALYSIS

The easy answer is, "You should do a transient analysis whenever you will have pressures greater than 10% above the Maximum Allowed Operating Pressure (MAOP) of your pipeline."  The next question that statement brings to mind is, "How do I know I will have transient pressures that reach 10% over my MAOP?"  Answer:  You will be sure you if one of these things happen,

1.       You experience an upset condition and pressures over 10% of MAOP are seen or recorded on monitoring equipment.

2.       You do a transient analysis in advance of system commissioning and it is confirmed that you will not experience over-pressures.

3.       You have many years of experience in the operation of your system and have never experienced over-pressures and plan to make no adverse operational changes in the future.

Otherwise, If you are still in the planning or design process, you have right now a very good opportunity to ensure safe system operation and regulatory compliance before any problems can develop.

All the above aside, it is generally accepted that transient pressures and flows can become significant when any of the following conditions exist or may occur,

1.       The fluid velocity is greater than 4 fps (1.2 m/s) at some point in the system.

2.       If there is a chance that a pump or driver trips (on or off), when not intended to do so.

3.       If there is a chance that a valve could fail.  A flow or pressure control valve or regulator, a check valve or a motorized valve actuator are usually subject to a certain amount of failures or a failure to position properly during their lifetimes.

4.       If the safety factor of pipe or equipment less than 3.5 times the operating pressure.

5.       If an emergency shut-down system is in operation where fast acting valves can open or close, relief valves activate, or pumps are automatically tripped.

6.       If there are valves between high pressure rated piping or equipment and low pressure rated piping or equipment.

7.       If there is a point in the piping where pressures lower than the vapor pressure of the contained product may be experienced at some time.

8.       If there is a single pipe or a pipe network that extends for more than 1000 feet (300 m).

9.       If surge equipment is required by specification or design code.

Even if none of the above are true, and with an eye towards maximizing system utilization per dollar invested while still considering safety as paramount, one could argue that, if a system is designed such that it never is expected to reach high pressure, it would be an overly conservative design.  If that were indeed the case, it should also be that there would be room to improve capacity by operating closer to allowed limits.  Transient analysis can determine the optimum operating point for which the cost of additional safety equipment verses a hard pipe design can be optimized and thus obtain maximum economic leverage for your investment.

ADVANTAGES OF A DETAILED ANALYSIS

The useful information that can be obtained from a detailed transient anlaysis of a piping system include the following, these are by no means all inclusive,

·                         Accurate design responses for equipment and pipeline in both steady state and transient conditions.

·                         Realistic pressures predicted all along the pipeline during steady state and during transitions between products, flowrates and emergency events or other upset conditions.

·                         Transient analysis includes the effective bulk modulus for accurate prediction of the travelling velocities of flow and pressure waves.  Multiple intersecting waves are algebraically added and properly attenuated.

·                         Valve operating times can be adjusted to minimize transient pressures and to prevent vaporization of the product. timing problems can be discovered and appropriate modifications can be made before the commissioning phase.

·                         Maximum pressure thrust loads can be determined for anchor points without making overly conservative assumptions.

·                         Equipment response to pressure and flow upsets can be investigated in detail, such as actual required relief volume capacity for tank sizing purposes.

·                         Methods of operation can be investigated to determine if there will be resulting adverse effects which can be corrected before equipment is damaged.  True minimum flowrates can be investigated for overheating pump seals and bearings and operation procedures changed in advance

·                         The true need for surge relief equipment can be determined and, if it is required, it can be appropriately sized.

·                         Surge relief equipment can be optimized, checked for adequate capacity and placed to protect critical locations.

·                         Leak rates and alarm levels can be checked for detectability, Leak detection system equipment and sensor locations can be optimized and detection limits can be determined in advance of commissioning.

·                         Locations of block valves to control pipeline spills can be optimized for both controllability, maintenance and spill control.

·                         Theoretical Leak volumes can be determined for sensitive areas along the pipeline and emergency equipment can be distributed along the pipeline in an optimum manner.   Realistic procedures can be put in place to control predicted spill volumes.

·                         Operation parameters of all auxiliary equipment, such as PID's, Control Valves, Temperature set points, Pressure regulators, Sensors and Actuators can be determined in advance for quick and easy reference during commissioning.

·                         Effects of pipeline start-up and shut-down can be determined in advance, such as determining when a hot and heavy crude flow will arrive at minimum average viscosity and finally reach the pipeline's design flowrate, or how long a hot pipeline can be shut down and still be expected to be able to reach maximum flow capacity within 1 week of restart.

·                         Maximum survivability of maintaining contract flowrates should a partial or total system shutdown be necessary.

Talk to us to find out if there are other more specific advantages to be found in analyzing your system.

in-line inspection are the three basic methods available for operators to use for assessing the integrity of their pipelines.

Direct assessment consists of direct examinations at pre-determined locations on a pipeline where potential external corrosion, internal corrosion or stress corrosion cracking might exist.  The direct examination locations are chosen on the basis of indirect inspection surveys or by modeling.  Direct assessment would usually be used only if in-line inspection or hydrostatic testing are not feasible options.  Additionally, Direct assessment is not currently allowed by DOT for liquid pipelines without a waiver. 

Hydrostatic testing has the major disadvantage of requiring that a pipeline must be out of service for extended periods of time, and it is considered a destructive test, since location of a defect requires that the pipeline experience a leak or rupture during testing. Disposal of hydrostatic test water can also be difficult and expensive due to environmental considerations.

Since in-line inspection does not usually require a pipeline to be taken out of service, and gives accurate location of defects nondestructively, it is often the preferred method of integrity assessment. However, not all pipelines were designed with in-line inspection in mind.  Pig launchers and receivers may be inadequate or may not exist at all. 

Diameter restrictions, sharp bends, check valves or reduced port valves, large diameter side taps, or other physical features may exist which would damage an inspection tool or cause it to become lodged in the pipeline.  Prior to in-line inspection, a detailed examination of the physical and operational aspects of a pipeline to be inspected is necessary to ensure that in-line inspection is feasible.  In some cases, minor adjustments can be made to the inspection tool with no pipeline modifications required to facilitate inspection. In others cases, it may prove that in-line inspection is not practical because of the major expenses required to make a pipeline piggable.  Inspection tools may also have other restrictions, such as pressure, temperature and product compatibility concerns. 

Pipeline operators should complete a questionnaire which evaluates all physical and operational aspects of a pipeline to assist in determination of pipeline piggability and to help choose the appropriate in-line inspection tool.³    

PHYSICAL RESTRICTIONS

Depending on the in-line inspection contractor and the specific tool selected, the physical restrictions for the tool will vary.  Specification sheets for each specific tool will usually identify the restrictions and provide maximum and minimum values for the pertinent parameters.  The following are the main items which need to be considered. 

Launchers and Receivers

In-line inspection tool specification sheets will usually give minimum length requirements for the nominal and oversize portions of the launchers and receivers for each type and size of inspection tool.  If reliable drawings of existing launchers and receivers are not available, it will be necessary to field verify the dimensions.  The tool vendor will usually provide access area and lifting requirements for the launcher and receiver areas which will need to be checked for adequacy.  If launchers and receivers do not exist, the pipeline will either need to be modified by installing permanent launchers and receivers or temporary ones will need to be used during the inspection.

The oversize portion of a launcher should be at least as long as the inspection tool.  This allows the front (drive) cups of the inspection pig to seal in the nominal pipe a very short distance downstream of the reducer while allowing the trap to be closed.  If the oversize portion is too short, it may be difficult to push some articulated pigs far enough into the nominal size pipe to allow closing the launcher.  Additionally, even if it is possible to push the tool further past the reducer, the launcher isolation valve may be too close to allow the pig to be fully inserted into the launcher.  The nominal size portion of the launcher needs to be long enough to allow the drive cups of the inspection tool to seal without the front of the pig contacting the launcher isolation valve.

The nominal portion of a receiver should be at least as long as the inspection tool.  This ensures that once the drive cups of a pig pass the reducer and lose their seal, the trailing end of the pig is clear of the receiver isolation valve.  Otherwise the pig may stop prior to completely clearing the valve.  If this happens, depending on the product and flow rates available, it may not be possible to move the pig far enough to close the isolation valve.  The length of the oversize portion of the trap is not as important for receivers as it is for launchers since it is much easier to pull an articulated pig through the nominal size pipe than to push one in.  The oversize portion should be long enough to accommodate the stopping position of the pig without contacting the closure door.

Bends

     The minimum negotiable bend radius is an important restriction to be considered.  Most in-line inspection tools are designed to negotiate factory bends with a radius of 3-D (3 times pipe diameter) or greater.  Certain tools are even capable of negotiating a 180^O 1-radius bend.  Some tools however, depending on pipe diameter, comma added require a minimum bend radius as high as 9D.  Additionally, the in-line inspection contractor will usually specify a minimum bore at bends which is more restrictive than their specified minimum bore for the line pipe.

Internal Coating

     Internal coating will interfere with data collection for some in-line inspection tools.  Additionally, some tools may damage internal coatings, which would not be acceptable to the pipeline operator. The inspection contractor should be made aware of the specification of any internal coating which may be present in the pipeline who should in turn advise the pipeline operator of any compatibility concerns. 

Wall Thickness

     In-line tools have a range of pipe wall thicknesses which they are capable of inspecting for metal loss within the desired tolerance.  The lower wall thickness limit needs to be considered, but is usually not an issue.  Magnetic flux leakage (MFL) tools report metal loss as percent of pipe wall and have an upper wall thickness limit of anywhere from 0.375” to over 1.00” depending on the specific tool and vendor. Ultrasonic tools measure and report actual remaining wall and generally have a higher upper limit than MFL tools. Some ultrasonic tools do not even specify a maximum wall thickness.  Prior to inspection, wall thicknesses of the line pipe throughout the length of the pipeline will need to be determined to be sure the appropriate inspection tool is chosen.   

Pipe Inside Diameter (Bore)

The outside diameter of line pipe for any given nominal pipe size is constant.  Therefore the mismatch at the transition between different wall thicknesses will always be on the inside of the pipe.  Inspection tool vendors will usually specify a maximum and minimum continuous allowable bore, and a maximum allowable step at transitions for each nominal pipe size for each specific tool.  If the maximum allowable step is exceeded, the tool can become damaged or stuck.   If wall thickness differences are too great, multiple inspections with different tool configurations may be required to complete the inspection of a pipeline segment.

Mainline Valves

     The manufacturers and bores of mainline valves in the pipeline to be inspected need to be determined.  Some older pipelines will actually have mainline valves of a smaller nominal size than the pipeline itself.  For example, there are 24” pipelines in existence which have 20” mainline valves.  In these cases, in-line inspection would require replacement of the valves or the use of temporary launchers and receivers in each valve section. 

     Even if valves are the same nominal size as the pipeline, they still may have a smaller bore than the line pipe.  In-line inspection vendors will usually specify the minimum bore for ball valves and gate valves through which their tool can pass without damage.  This minimum local bore restriction will be somewhat smaller than the minimum continuous bore.  Some gate valves will have a void equal to the thickness of the gate when in the fully open position.  If the drive cups of the inspection tool lose their seal at this cavity, the tool may stop at the valve and the available pressure may not be enough to move it any further.  It might also be possible for the front cup to nose down and lodge in the void.  In either case it would be necessary to shut down the pipeline and remove the pig by cutting it out.  This problem can be avoided by adding an extension on the front of the pig with an additional drive cup.  The two drive cups should be spaced so that at least one cup is sealed at all times when passing the cavity in the valve. 

     Operating procedures should also specify physically checking all the mainline valves to be sure they are fully open prior to any pig runs to avoid pig or valve damage.

Check Valves

     Check valves are also a potential problem for in-line inspection.  If check valves are present in the pipeline, the inspection vendor will sometimes require that the clappers either be removed or locked in the open position to avoid damaging the tool.   Check valves will also have a void which will need to be spanned by the drive cups at all times while passing.   The void can be compensated for in the same manner as for the gate valves.  Manufacturer’s drawings for each different check valve should be carefully reviewed.

Barred Tees

     Full size branch connections (tees) in the pipeline should be barred to prevent the front of the inspection pig from becoming lodged.  Unbarred tees may be found in some older pipelines, even at the receivers.  It is usually not necessary to replace these with barred tees to accommodate in-line inspection, but extreme caution should be exercised while running in-line inspection tools or any other type of pig with unbarred tees in the pipeline.  It is important that the pig not be allowed to stop at an unbarred tee, especially if there is any flow going from the mainline through the tee into the branch, such as at a receiver. It may be possible to start flow from the branch to the mainline to realign the pig and assist passage.

Intrusive Devices

     The pipeline should be checked for any installed facilities which may protrude into the pipeline and interfere with pigging.  Intrusive devices such as insertion flow meters, internal corrosion monitoring devices and siphon drains are some examples of facilities which would need to be removed prior to pigging.

OPERATIONAL CONSIDERATIONS

Tool Speed

Tool speed is an important consideration when the inspection is planned to be run with product on-stream.  If speed requirements cannot be met during normal operations, it will not be feasible to perform an inspection without taking a pipeline out of service.  All inspection tools have an optimum velocity range in which they can collect usable data.  Most free swimming tools are run in the range of 1 to 7 miles per hour, whereas tethered UT tools are run at much lower velocities of about 0.2 to 0.4 miles per hour. For on-stream inspections, product flow must be maintained within the desired range.  This can result in lost throughput (and lost revenue) for pipelines which usually operate at higher velocities. 

Product Compatibility

     Products may contain corrosive compounds such as hydrogen sulfide which would result in damage to inspection tools unless they are specially modified.  The tool vendor may even need to build a custom made tool out of special materials to accommodate corrosive products.  These pipelines usually operate at pressures higher than most tools can accommodate, and the carbon dioxide exists in a supercritical phase where it behaves more like a liquid than a gas.  Supercritical carbon dioxide permeates all of the elastomers present in the pig such as the cups and the wiring and causes them to deteriorate rapidly.  The combination of the permeation and the extremely dry environment existing in carbon dioxide pipelines also causes rapid cup wear.

     Most ultrasonic in-line inspection tools require a liquid couplant between the sensors and the pipe wall to function.  These tools are therefore more suitable for liquid lines than for gas.  In order for ultrasonic tools to be run on-stream in gas lines, they must be run in a slug of liquid between two other pigs to provide the couplant.

Temperature Limitations

     In-line inspection tools will have specific temperature ranges in which they can function properly. If pipelines operate outside of the acceptable temperature range, they cannot be inspected while in service. 

Pressure Limitations

All tools have a maximum pressure limitation.  When run in gas lines, tools will also have a minimum pressure limit.  The minimum required gas pressure is highest for small diameter pipelines.  For instance in 4” pipelines, one vendor requires a minimum of 1000 Psig.  At lower pressures, pigs will not run smoothly but will start and stop, even in continuous bore pipe.  Pneumatic jumping might occur in lower pressure gas pipelines where static friction coefficients are prevalent.  Pigs will also tend to stop at restrictions such as transitions to heavy wall pipe or reduced bore valves for long periods of time.  While stopped, pressure builds behind the pig until it breaks loose and surges forward at a high rate of speed, likely outside of the desired velocity range.  When this happens, insufficient data is collected for this portion of the run.  Surging such as this also increases the chances of the tool being damaged.  At higher pressures, the gas acts more like a non-compressible liquid and reduces or eliminates the surging effect.

FINAL PREPARATION

Pipeline Cleaning

     Pipelines should be as clean as possible prior to inspections.  Solids present on the internal pipe walls will interfere with data collection and may even cause the inspection tool to become lodged in the pipeline.  The pigging history of the pipeline should be reviewed to determine what type of cleaning program may be required.  Multiple runs with steel brush cleaning pigs are sometimes necessary to achieve an acceptable cleanliness level for in-line inspection.

Gauging

Once all known physical piggability issues have been resolved, as a minimum, a gauging pig should be run to determine if there any unknown restrictions such as dents, buckles or ovalities in the pipeline.  The gauging plate should be made of aluminum and should be of a diameter large enough to detect any internal diameter restrictions which are outside of the in-line inspection tool’s stated minimum bore requirements.  Of course, the gauging pig will not provide the location of any restrictions which may have damaged the gauging plate during the run. 

If the gauging plate is damaged, it will be necessary to run a geometry tool to locate the restriction causing the damage so it can be removed.  Geometry tools are designed to pass through restrictions of 25% or more of the pipe diameter.  Running of a geometry tool also has the added benefit of verification of all other information regarding bends and inside diameter issues.  Some in-line inspection contractors will also provide a “dummy” tool which will have weights and dimensions similar to the actual inspection tool.  The tool manufacturer may require that a successful “dummy” run be executed prior to the actual inspection run.

CONCLUSIONS

     It is essential that piggability of a pipeline be ensured prior to in-line inspection.  The operator should develop a check list considering of all the items discussed in the previous sections.  As a minimum, a gauging and/or geometry tool should be successfully run as a final check prior to the actual inspection.

Insufficient research and preparation prior to in-line inspection can result in inspection tools being damaged or destroyed, and may result in the necessity of an expensive pipeline shutdown to recover the tool.  Furthermore, the inspection may provide little or no useable data about the condition of the pipeline.  In either case, a considerable expense will be incurred by the operator with very little benefit to show for it.  The cost of modifications required to make in-line inspection possible should also be weighed against the cost of direct assessment or hydrostatic testing for integrity assessment. 

REFERENCES

1.   US Department of Transportation 49 CFR Part 192, “Transportation Of Natural And Other Gas By Pipeline: Minimum Federal Safety Standards”, Subpart O, “Pipeline Integrity Management in High Consequence Areas”.

2.              US Department of Transportation 49 CFR Part 195, “Transportation of Hazardous Liquids By Pipeline”, Subpart F, Paragraph 195.452, “Pipeline Integrity Management In High Consequence Areas.”

3.   NACE Standard RP0102-2002, “Standard Recommended Practice, Inline Inspection of Pipelines”, Appendix A.