erosional gas velocity

Gas Erosional Velocity Discussion

2012 Pipeline Knowledge Retention Conference Houston, Texas November 6-7, 2012

Panel Members

Chris Williams Cheniere

Eileen Steinbach DCP Midstream

Ron Matthews Emeritus

Anders Johnson Kinder Morgan

Ken Skweres Spectra

Thomas Rey Gregg Engineering

Erosion Velocity Discussion

� Definition

� Importance

� Factors

� Examples

� Measurement techniques

� Mitigating options

� Safety is No.1 prudent designs No. 2

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Note the points made in these presentations are for discussion purposes only. Engineered systems must be designed by qualified individuals that account for the site specific conditions.

3Erosion – Definition

�Erosion is the loss of material due to solid or liquid particle impact on the material’s surface

� “It is a battle of the steel’s yield stress and fracture

mechanics vs. the surface morphology” 1

� Important for piping systems since loss of material

leads to wall thinning and loss of pressure containing

capabilities

�For correctly designed transmission line systems,

problems due to erosion are rare

1 “Understanding equipment erosion”; Ray Cocco, PBE October 2012, www.powderbulk.com

4Factors Affecting Erosion

�Particle Speed & Mass

�Material MOE/Ductility

�Particle Angle of Attack

�Particle Concentration

�Material Surface Roughness



5Where Erosion Shows Up

�Bends/Changes in Direction




�Blind Tee’s

�Headers


�Reducers

�Re-enforced Welds

8Calculating Permissible Velocity

�API RP 14E

�Basic Equation� Vmax in f/s

�Terms

� Note – This is not a ‘one size fits all’ equation there are many factors which we will explore in a real world example

Equation9


10Case Studies

� Meter Station example

�DCP Midstream



Velocity concerns associated

with particle entrainment in a

meter tube

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Particle build-up/dropout

observed in the meter tube12

Meter tube has been in service for several years – no indications of wall

loss within the tube. However observed particle dropout warrants further

investigation. Ascertain what is happening to the downstream piping


Gas analysis

� Pipeline quality gas

� 1023 BTU

� Upstream filtration

� No indication of free liquids

� Solids observed in the meter tube

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Pipe Velocities – Pipe, Fittings,

and Appurtenances

Flow Rate

(MCFD)

Pressure

(PSIG)

Pipe I.D.

(INCHES)

Temp

(Deg. F)

Velocity

(FPS)E

lbow

110,000 230 15 40 63

124,000 230 15 40 71

150,000 230 15 40 85

200,000 230 15 40 114

220,000 230 15 40 125

275,000 230 15 40 157

Valv

e

110,000 230 9 40 174

124,000 230 9 40 196

150,000 230 9 40 237

200,000 230 9 40 316

220,000 230 9 40 348

275,000 230 9 40 435

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Check velocities through the entire flow path – time of day, time of year

Observations

� Pipe O.D. 16”

� Pipe wall 0.500”

� Pipe Grade X-42

� Seamless pipe

� Velocity estimated to exceed 100 feet/second based on meter flow and delivery pressure hundred of hours per year

� No readily discernable excessive wear using ultrasonic thickness measurements

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Measurement Techniques and

Analyses

� Ultrasonic thickness indicator

� Grid pattern established for measurements

� X-ray

� Magnetic Particle (SCC)

� Examine upstream piping

� Component(s) in question

� Downstream piping

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Measurement Techniques and

Analyses

� Ultrasonic thickness indicator readings

� Downstream piping wall variations were observed but are not unlike any inspection of seamless pipe

� 93.5% of nominal 500 wt = .4675" minimum allowed wall thickness

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Recommendations

� Annual check of high velocity piping where entrained particles may be present using ultrasonic measurements

� Complete flow path study

� Meter tube inspection

� Gas analysis

� Coupons – optional

� X-ray

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Conclusion

� Pipeline gas velocity is not a sole determinant

� In this example there was no readily discernable excessive wear based on the ultrasonic thickness measurements in spite of possible particle entrainment and bends in the flow path

� Traditional “rules of thumb” may be overly conservative for pipeline quality natural gas systems

� Careful checks should be made but automatic pipe replacements avoided unless there is a reason to believe there is a safety issue

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Thank You

Questions?



Chris Williams Cheniere

Eileen Steinbach DCP Midstream

Ron Matthews Emeritus

Anders Johnson Kinder Morgan

Ken Skweres Spectra

Thomas Rey Gregg Engineering

References:

� DNV Recommended Practice RP O501, “Erosive Wear in Piping Systems; http://www.dnvusa.com/industry/maritime/rulesregulations/dnvrules/offshorecodes/recommendedpractises.asp

� “Understanding equipment erosion”; Ray Cocco, PBE October 2012; www.powderbulk.com

� Course No O-5001, “Gas Pipeline Hydraulics”; www.pdhengineer.com

� API RP 14E, “Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems”; http://www.api.org/publications-standards-and-statistics.aspx

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erosional gas velocity

Documents

engineered systems

discussion purposes

site specific conditions

qualified individuals

piping systems

erosion definitionerosion

loss of material

loss of pressure