Erosion Velocity 2

[shvet]

Hi, forum

I know this topic has been started a lot of times before. Actually I used "search" button but haven't found precise answer. We have a particular problem with predicted erosion velocity in steam condensate header of an existing petroleum unit. To get to know steam traps pressure drop we use simulation software - it helps us to save time. Software we use is designed for plant piping systems and it suggests to calculate erosion velocity according to API 14E. We knew that coefficient C in API 14E is conventional and C value has been criticised but it gave us a some safety margine. All was OK and software gave us reasonable results till now.

In current steam condensate header model we encountered that predicted erosion velocity of two phase flow is equal 6-10 m/s. My questions are next:

1. API 14E is designed for oil and gas pipilines. Could it be implemented for other service: steam, chemicals, refining processes?
2. Erosion prediction in API 14 is designed for two phase flow. Could it be implemented for near gas conditions, for example saturated steam, saturated vapors? Could it be implemented for all liquid conditions?
3. Are there any worth engineering (not academic) sources to know more about erosion prediction? Sorry, I understand that a lot of researches have been done and subsequent books and theses have been written. But we operate with real life and real pipe, I need more engineering instead of scientific.
4. What would you do for steam condensate header check? What are your practices? And the most important - what are the reasons and sources of your practices?
5. What software do you use for inplant hydraulic systems? Which of industry is yours (storage/refinery/petrochemical/chemical/fertilizers/energy)?

P.S. Sorry for language - I have seldom practice. You can state which part of text is hard to take.

 

[zdas04]

The answer to your questions in my experience is:
[ol 1]
[li]Yes, it is just as bad on steam or chemicals as it is in crude. I've seen lines that were well under the erosion velocity experience erosion and lines way over that didn't.[/li]
[li]API 14 is absolutely wrong on any predominantly gas line. The equation came from empirical experiments with various liquids and simply does not translate to gas at all.[/li]
[li]Historically we've moved from the "scientific" to the "real" through the work of engineers doing "science" (e.g., both Turner and Coleman were engineers working on understanding vertical multiphase flow, and their correlations are now ubiquitous in upstream gas operations). We've gotten "good enough" results from the API 14 calculations so there hasn't been a driving force for engineers to advance our understanding of erosion. I have done some experiments with predominantly gas two phase flow and I was unable (even at very high velocity) to initiate erosion in a gas flow without significant particulate inclusion, but those experiments were far from comprehensive.[/li]
[li]Sorry, I can't help with this one.[/li]
[li]I can't help with this one either[/li]
[/ol]

As to your language skills, you have absolutely nothing to apologize for, after reading your last line I went back and re-read your post and your word choices and grammar are at least on par and actually a bit better than most of the native-English-speakers on the Internet.

[bold]David Simpson, PE[/bold]
MuleShoe Engineering

In questions of science, the authority of a thousand is not worth the humble reasoning of a single individual. Galileo Galilei, Italian Physicist

 

[Artisi]

David: nice to see a well put together question for a change and a great answer including the compliment on language.
Way off my field of experience, but certainly worth a star.
Ian

It is a capital mistake to theorise before one has data. Insensibly one begins to twist facts to suit theories, instead of theories to suit facts. (Sherlock Holmes - A Scandal in Bohemia.)

 

[SJones]

3. When talking about "prediction," it is not going to be anything other than theoretical unless a full scale, identical system is built,operated and measured. For oil & gas, the University Of Tulsa Erosion Corrosion Research Centre is the go to place. Try their papers, particularly SPE 166423.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[mk3223]

In your plant, was there an erosion happened in the steam condensate line as predicated by the calculation?
My experience regarding the operation of the condensate system was the water hammer issue happened because the condensate pipe was undersized. The volume of the flashed steam inside the pie is much higher than that of water, which could be >90% in volume, because of the density differences. There are many commercial recommendations for the condensate line sizing, such as Armstrong, TLV, etc. After selected the pipe size, check for the desired flow pattern of the two phase flow for the condensate line.

 

[georgeverghese]

API RP 14E velocity limit predictions have had their day in the sun, and is generally considered obsolete these days. What may be perceived to be erosion corrosion could actually be due to chemical or microbial contamination of the fluid stream. In the case of steam, a common cause would be high dissolved O2 in the 2phase condensate stream. Another cause could be cross contamination of the steam with corrosive process fluids at the upstream HX through some leak.

 

[shvet]

to zdas04
Thanks a lot

to SJones
Thanks a lot.
1. Exactly. I asked for "engineering practices instead of scientific" in meaning of "a full scale, identical system is built, operated and measured". I would add "analyzed and formulated in a recommended practice or a standard/code by experienced and qualified engineer or team of engineers".
2. I've found SPE 166423 and it seems great. A glance across SPE 166423 reveals that API 14E is wrong.

to mk3223

In your plant, was there an erosion happened in the steam condensate line as predicated by the calculation?

We are in charge of existing petroleum unit revamp and are not dealing with operation and maintenance. Actually unit is ~15 years old and Operator did not ask us to solve any problem with pipe network thinning. Erosion is expected in bends and tees and as you know these details are not intended to be controlled by periodic thickness measuring. Straight runs of pipe are more convenient for defectoscopist to work with.
We do not work with existing situation in unit condensate header. We deal with situation after unit revamp and subsequent operation during unit life time.

There is a record of erosion in flare header. Operator had flare subheader erosion in reactor section of vacuum gasoil hydrocracking. Downstream of high pressure separator depressuring relief control orifice bends were eroded and leak after several emergency depressuring events. Operator had to replace them with new one.

There are many commercial recommendations for the condensate line sizing, such as Armstrong, TLV, etc.

We do in roughly the same way. There are a lot of recommendations and concerning condensate header some companies recommend quite high velocity while some companies recommend quite low velocity. High velocity guarantees homogeneous flow pattern, low velocity guarantees low kinetic energy. As I understood there is no generally accepted point.

to georgeverghese

API RP 14E velocity limit predictions have had their day in the sun, and is generally considered obsolete these days.

Technical committee ISO/TC 67/SC6 disagrees with you. It reviewed and confirmed ISO 13703:2000 in 2015. Erosion velocity prediction in API 14E and ISO 13703:2000 are identical. See para. 5.5.1 ISO 13703:2000.

 

[SJones]

@shvet - how many systems do you think would have to be built, operated, analysed and codified in order to cover every scenario for a standard? It just isn't possible, that's why it's down to theory, common sense, and the 'how lucky does one feel' syndrome.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[LittleInch]

I've always felt that one consideration you need to think about is how each material and fluid interact with each other.

So e.g., if you have an acid gas and using a material which relies on a layer of oxide as it's protection against corrosion, you're in a much more vulnerable position than if wear on the surface from liquid impingement in a mainly gas system has a less important effect.

As ever with 14E, it's choosing the C factor which becomes all important...

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[georgeverghese]

Exit lines from HPS depressure valve would be seeing high liquid entrainment rates during depressure, so this again may be due to corrosive components in the liquid in the HP sep - H2S or chlorides perhaps.

 

[MortenA]

want something more than API 14 that you can still do in a spreadsheet?

Try google DNV-RP-O501 (remember to get the 2015 ed.):

http://rules.dnvgl.com/docs/pdf/dnvgl/RP/2015-08/DNVGL-RP-O501.pdf

Its pretty comprehensive - but it wont get you a nice "max erosinol velocity" the same way API will....

Best regards, Mirten

 

[NovaStark]

I am having a similar problem due to steam erosion as a result of two phase flow which causes eventual pipe wall loss and hence leaks.

The above posts indicate that API 14E should not be used for steam. Which when reading it I tend to get that. The above DNV document are specifically for sand in oil production.

I have yet to get the SPE document. Can the SPE document reliably be used for modeling erosion due to two phase steam flow ?

 

[shvet]

to SJones

how many systems do you think would have to be built, operated, analysed and codified in order to cover every scenario for a standard?

My own view:
To cover 80% problems - one pilot unit
To cover 90% problems - one full scale unit
To cover 95% problems - 3-4 full scale units during 4-5 years in service
To cover 98% problems - 10-20 full scale units during 15-20 years in service
To cover 100% problems - never

It just isn't possible, that's why it's down to theory, common sense, and the 'how lucky does one feel' syndrome.

I disagree with you. There are a lot of good standards and practices that were made by technical committees or team of engineers. All huge corporations (e.g. Shell, ExxonMobil, UOP) have groups of engineers that analyse facilities in service and codify internal standards and recommended practices. By example of Shell some of this information were transferred to ISOs.

to LittleInch

As ever with 14E, it's choosing the C factor which becomes all important...

Do you mean that API 14E / ISO 13703 erosion prediction is worth to follow?

to MortenA

Try google DNV-RP-O501 (remember to get the 2015 ed.):

Does DNV-RP-O501 relate to two phase flow induced erosion? As NovaStark has just mentioned DNV-RP-O501 deals with sand erosion.
"... This recommended practice is developed for the oil and gas industry to provide guidance on how to safely and cost effectively manage the consequences of sand produced from the oil and gas reservoirs through production wells, flowlines and processing facilities. The ultimate goal of this document is to assist prevention of incidents related to sand that may cause harm to people, environment or assets and without causing unnecessary restrictions to production performance. ...
Sec.3 to [4.12] of this document provides empirical models for prediction of particle erosion in standard pipework components..."

Can anybody help me with SPE 166423?
As it is mentioned in fig. 7 of SPE 166423 to get erosion rate mm/year user shall use equation:

mm/year = ERli * Vdrops / Ap.

where ERli - erosion ratio from eq. 3
Ap - projected impact area
Vdrops - unknown

Can anyone explain:
- what is Vdrops, how it can be obtained?
- which is units in eq. 3 and fig. 7 (customary, SI, metric)?

 

[SJones]

By example of Shell some of this information were transferred to ISOs

Indeed, that is as may be, but when it comes to downstream oil & gas erosion, Shell leaves itself completely in the hands of U of Tulsa ECRC.

Volume loss of the material is obtained by multiplying erosion ratio (from Eq. (3)) by the total volume of the droplets impinging the pipe wall in a given area that is assumed to be the projected pipe area. Finally, thickness loss is equal to volumetric loss divided by projected impact area, Ap.

V[sub]drops[/sub] appears to be the total volume of droplets impinging the pipe wall

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[shvet]

Vdrops appears to be the total volume of droplets impinging the pipe wall

Do you know which units are? Is it m3(liq)/m3(mix), m3(liq) a year, m3(liq) a hour, mm3(liq) a year?

Indeed, that is as may be, but when it comes to downstream oil & gas erosion, Shell leaves itself completely in the hands of U of Tulsa ECRC.

I didn't understand what you are talking about. I haven't found a connection between Shell and University of Tusla E/CRC

Shell use ISO 13703 as referenced standard in it's DEP.

3.24 FLOWLINE DESIGN
3.24.1 General Requirements
Flowlines shall be sized in accordance with ISO 13703.

The same way Total does.

12.3.2.3 Erosion and Corrosion
...
a) Erosion produced by liquid droplets in a sand-free environment by corrosive fluids
The erosion velocity Ve, below which a tolerable amount of erosion occurs, can be obtained from the following empirical equation indicated in ISO 13703 / API RP 14E:
Ve=c/sqr(ρm)
where:
Ve = fluid erosional velocity, m/s,
ρm = gas/liquid mixture density, kg/m3,
c = empirical constant, kg1/2/(m1/2.s). c values depend upon material and type of service and are given in the table here below.

The same way Norsok does.

6.4 Sizing of gas/liquid two-/multiphase lines
Wellhead flow-lines, production manifolds, process headers and other lines made of steel and transporting two-phase or multiphase flow, have a velocity limitation. When determining the maximum allowable velocity, factors such as piping geometry, well-stream composition, sand particle (or proppant) contamination and the material choice for the line shall be considered.
As a guideline, the maximum allowable velocity can be calculated by:
V = 183*sqr(1/ρmix)
where
V is the maximum velocity of mixture in m/s
ρmix is the density of mixture in kg/m3

The same way Foster Wheeler does.

Erosion and corrosion
In broad terms, erosion and corrosion are often observed to be worse in twophase flow than in single phase flow. In many cases, this is due to removal of an otherwise protective scale or film, particularly by the droplets that occur in annular flow. A frequently used criterion for determining the onset of erosioncorrosion damage in two-phase lines is the API14E equation. This states that if the local flow velocity exceeds a critical velocity, then there is a risk of erosioncorrosion. The expression for the critical velocity is:
Uc=(1.22*C)/(sqr((1-e)*pL+e*pV))
Uc is the critical velocity in metres per second, and pL and pV are respectively the liquid and vapour phase densities measured in kg/m3. e is the voidage, which is evaluated by the methods given in section 5. The constant C normally has a value of 100 for continuous flows, and 125 for intermittent flows.

As I understood the same way Chevron did, unfortunately it's Piping Manual PIM800 that I have went out of date.

 

[SJones]

Your Shell quotes are way out of date but, nevertheless, they do work with prescriptive velocity limitations, in the absence of entrained solids, in the piping design standard: DEP 31.38.01.11-Gen, which is owned by the mechanical engineers and is used for preliminary pipe sizing. Naturally, in the scheme of large organisations, the materials & corrosion engineers then go and throw a curve ball into the works with DEP 39.01.10.11-Gen, which states:

"Non-corrosive fluids without solids
The mixed phase velocity limit shall be 100 m/s (328 ft/s) for CRA and 30 m/s (98 ft/s)for carbon steel: . Velocities up to 80 m/s (263 ft/s) may be acceptable for carbon steel subject to assessment (e.g., by CFD).

Velocities shall be based on well documented field experience in identical fields, or based on laboratory studies (flow loops)"

Another Shell standard, DEP 30.75.10.10-Gen, states the following for steam condensate headers:

"Size the line for normal operating condensate mass flow with a flash steam velocity of 10 m/s (33 ft/s) or less."

Your compilation of standards shows that, in the absence of entrained solids, organisations tend to accept the convenience of ISO 13703/API RP 14E and derivatives thereof, neglecting the tendency for under or over prediction as compared to the more applied work discussed in SPE 166423.

Erosion ratio seems to be dimensionless, so V[sub]drops[/sub] and A[sub]p[/sub] have to have units that compute to mm year[sup]-1[/sup]


Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[shvet]

Shell leaves itself completely in the hands of U of Tulsa ECRC

I have found. Thank you.

The development of erosion modelling and erosion rate calculations has been ongoing for several decades. Significant contributions were made by researchers at the University of Tulsa, AEA Harwell, and by Y.I. Oka. These studies have resulted in models that might be used in evaluating erosion in pipe components, pipelines, or facilities. The model that shall be used for analyzing erosion due to solids in production systems is the SPPS model developed by the University of Tulsa.
Before models were available the only approach to designing for erosive service was the use of the API RP 14E formula that addressed corrosive service with solids production. It has been demonstrated that at low sand production rates this formula is conservative, whereas at high rates it underestimates erosion rates. Therefore the API RP 14E formula shall not be used.

 

[drrust]

A lot of the replies on this forum refer to new information, e.g. from the University of Tulsa. Back in 1984 I was working at Amoco's research lab in Tulsa, and we looked at API 14E. The results of this work appeared in a 1985 paper: R. Heidersbach, "Velocity Limits for Erosion Corrosion," Paper No. 4974, Proceedings, Offshore Technology Conference, Houston, Texas, May 1985.

I talked to engineers at a number of other oil companies, and the best advice I could get came from someone at Mobil in their Dallas-area offices. They were operating as fast as possible and ignoring the API RP14E guidelines.

The short version of this paper, as I remember over 30 years later:

The API RP14E erosion velocity formula came from the steam-generating power industry. It was originally developed because of steam line problems at PSEG plants, primarily in New Jersey. By 1984 it was adopted by the oil patch, with no empirical data to support the application to downhole or topside erosion corrosion caused by produced fluids.

The power industry problem had to do with "low quality steam"--to a mere metallurgist like me that means steam with liquid droplets in it, although erosion (erosion-corrosion?) could also come from particulates.

In the years since 1985 I have been an observer, but not an active researcher on this problem.

To the best of my knowledge, no one has reported erosion-corrosion in single-phase fluid flow. The last input I had on this was from a nuclear power plant in California, where they were using proprietary EPRI software to predict where to concentrate inspections (primarily UT at bends in steam piping). The feeling of the plant's EPRI software guru engineer was that perhaps loose scale (iron oxides particulates) was the major problem, although low-quality steam (liquid impingement) could also be a problem.

 

[shvet]

Something is wrong with SPE 166423. Two days I'm trying to repeat the example in SPE 166423 (see text just below fig. 7). Please correct me where is my fault.

Input data
Metal = CS 1018
Erosion rate ER[sub]Li[/sub] = 6.5E-10 dimensionless
Thickness Loss Ratio TLR = 0.258 mm/y = 2.58E-4 m/y
DN pipe = 4 in = 100 mm = 0.1 m
Entrainment fraction (volumetric?) EF = 0.14 dimensionless
Gas superficial velocity = 30 m/s
Liquid superficial velocity = 0.09 m/s

Calculation
Impact Area A[sub]p[/sub] = πDN[sup]2[/sup]/4 = 3.14 * 0.1 m * 0.1 m / 4 = = 7.85E-3 m[sup]2[/sup]
Volume of dropless V[sub]drops[/sub] = TLR*A[sub]p[/sub]/ER[sub]Li[/sub] = 2.58E-4 m/y * 7.85E-3 m[sup]2[/sup] / 6.5E-10 = 3.11E3 m[sup]3[/sup]/y
Volume of dropless V[sub]drops[/sub] = 3.11E3 m[sup]3[/sup]/y / ( 8.76E3 h/y * 3.6E3 s/h) = 9.86E-5 m[sup]3[/sup]/s
Total volumetric flowrate (gas+liq)V[sub]total[/sub] = V[sub]drops[/sub]/EF = 9.86E-5 m[sup]3[/sup]/s / 0.14 = 7.04E-4 m[sup]3[/sup]/s
Mixture velocity (gas+liq) = V[sub]total[/sub]/A[sub]p[/sub] = 7.04E-4 m[sup]3[/sup]/s / 7.85E-3 m[sup]2[/sup] = 0.09 m/s

Output
My mixture velocity is equal to Tulsa's liquid superficial velocity. It makes no sense. If one considerS superficial velocity difference between gas and liquid then mixture velocity shall be between gas and liquid velocity. But instead of this mixture velocity is equal to liquid.

Does it mean next?
Two phase fluid goes through pipe with velocity 30 m/s, this fluid has 14% of liquid in form of ~200 µm droplets. These droplets strike impingement area with velocity 0.09 m/s (!) and cause erosion?
What?

 

[shvet]

A lot has been written, let me sum up:

1. In non-corrosive no-solids two phase service some erosion can occure. This erosion is a result of high velocity.
2. Threshold velocity can be considered:
- for stainless steel 80-100 m/s
- for carbon steel 30-80 m/s
3. For erosion prediction API 14E and ISO 13703 are widely used.
4. There known researches exist which state API 14E / ISO 13703 erosion prediction overestimates erosion velocity. This point is accepted by some huge oil and gas corporations design practices.
5. Instead of this API 14E / ISO 13703 are kept on in service in many companies.
6. Other erosion models were developed. These models were made on water/air and brine/air mixtures as these mixtures are easy to work with in laboratory. There is no signs these models were tested on real oil and gas facilities as a good engineering practice requires.
7. These models are not widely accepted. They are academic researches but not engineering practices. These models have no:
- limits of applicability
- accuracy
- reproducibility
8. SPE 166423 is general known as a good source that criticises API 14E / ISO 13703. Model in SPE 166423 can't be used as it has unknown input data:
- droplets diameter
- impact velocity
- total volume of droplets
9. Lack of good engineereng practice (and other non engineering reasons) is a reason why many companies keep on using API 14E / ISO 13703 erosion model.

Forum, please correct me where I'm wrong.