28 replies to this topic

[cnu879]

Hi All,

Cloud you please anyone help me to calculations of natural pipe line size.

Please find the attached steam velocity criteria at different pressures, is it applicable for natural gas pipe line sizing calculations?

• Generally gases consider maximum velocity 30 m/sec for pipe line sizing calculations, is it applicable applicable for all gases? for different pressures?
• is it available similar kind of velocity chart for natural gas also?

Natural gas conditions and properties:

Molar Flow : 35 MMscfd (35680 kg/hr)
Molecular Weight :20.43
Operating Pressure Barg: 75
Operating Temperature Deg C : 50
Density :68.62 kg/m3
Viscosity:0.014 Cp
Compressiblity factor:0.8261

Thanks,
Best Regards,
Sriniii

[breizh]

http://www.pipeflowc...com/naturalgas/

Hi ,Consider these resources to support your query.

Probably more info in GPSA (gas processors suppliers association).

Hope this helps

Breizh

Edited by breizh, 22 June 2012 - 01:13 AM.

[ankur2061]

cnu879,

A pipeline system needs to consider not only the velocity but also the pressure drop in the pipeline. This is specifically true when we are talking of long distance sales gas (natural gas) transmission pipelines and the required pressure at the terminal end of the pipeline governs the line size along with the velocity.

Velocity of 30 m/s is obviously very high. There are also considerations related to erosion due to high velocities which need to be taken into account. Companies like "Shell" recommend that gas velocities in transportation of natural gas through long-distance pipelines should be in the range of 5-10 m/s for continous operation and a maximum up to 20 m/s for intermittent operation.

The normal sizing procedure for gas transmission pipelines is to assume a line size and check the pressure drop and velocity for the assumed line size using equations for single-phase gas pipeline equations such as the AGA (American Gas Association), Weymouth, Panhandle A and Panhandle B. A very detailed excel workbook including all the above mentioned equations, calculation of flow or pressure drop based on these equations and calculation of erosion velocity is available at the online store of "Cheresources" at the following link:

http://www.cheresour...-pipeline-flow/

Hope this helps.

Regards,
Ankur.

[katmar]

I have found the Norwegian Oil Industry Association standards very useful for this sort of problem. They are amazingly concise, practical and clear. Search for NORSOK P-001. It is for topside offshore piping, but very useful for piping in general. As advised by Ankur, you must particularly balance the criteria of velocity and pressure drop for long distance pipelines. These standards are freely downloadable.

[Shivshankar]

cnu879,

NORSOK P-001 SIZING OF GAS LINES (Page 12-13)

When sizing gas lines the sizing criteria will be a compromise between the maximum velocity and allowable pressure drop

Maximum velocities

In lines where pressure drop is not critical, gas velocity shall not exceed limits which may create noise or vibrations problems.

As a rule of thumb the velocity should be kept below:

V = 175 X (1/ρ)^0.43

Where, V is the maximum velocity of gas to avoid noise in m/s and ρ is the density of gas in kg/m3.

When dP is not critical:
Velocity is 60 m/s (or the lowest value)

When dP is critical:
dP is set depending on the operating pressure.

Refer Table 4:Recommended pressure drop for operating pressure in NORSOK STANDARDS on page 13.

See attached NORSOK Standard P-001

Regards
Shivshankar

Attached Files

•  NORSOK P-001e5.pdf   90.25KB   2755 downloads

Edited by Shivshankar, 22 June 2012 - 07:48 AM.

[ankur2061]

Shivshankar,

Norsok P-001 guidelines are for gas piping and not for gas pipelines. These again are way over the top. Engineering companies like Bechtel allow a maximum dry gas velcoity with no solid particles as 100 ft/s (30 m/s) for piping. BP allows a velocity of 38 m/s for gas or vapour piping including super-heated steam.

I would not design a long-distance natural gas transmission pipe line for a velocity of more than 10 m/s normally unless the client says they can go to a higher velocity and provide this in writing. A recent job for a 600 km sales gas transmission pipeline of 52" inch size had velocities ranging from 9 to 10 m/s through the entire pipeline route.

Regards,
Ankur.

[kkala]

1. Following notes are from "Handbook of Natural Gas Transmission and Processing", by S Mokhatab, W A Poe, J G Speight, pages 418 - 421, Section 11.6 - Design Considerations on sales gas pipelines, subsection 11.6.1 - Line Sizing Criteria, Elsevier, 2006.
α. Most cost effective gas pipelines should have a pressure drop between 3.50 and 5.83 psi/mile. However for those pipelines (short ones) in which pressure drop is of secondary importance, the pipe could be sized on fluid velocity only.
β. In systems with CO2 as low as 1-2 %, velocity should be limited to 50 ft/s or lower, for it is difficult to inhibit CO2 corrosion at higher velocities.
γ. In most transmission pipelines recommended gas velocity is 40 - 50% of the erosional velocity.
As a rule of thump, pipe erosion begins when velocity exceeds the value of C/SQRT(ρ) in ft/s, where ρ = gas density (in lb/ft3) and C = empirical constant (in lb/s/ft2) (starting erosional velocity).
δ. C=100 in most cases. API RP 14E (1984) suggested C=100 for continuous and 125 for non continuous service. In addition C = 150 to 200 may be used for continuous, non corrosive or corrosion controlled services without solid particles present.
2. Attached "NGvel.xls" estimates starting erosional velocities, in function of operating pressure, for either the NG described by cnu879 or pure methane at 15 oC. The low erosional velocity corresponds to C=100, the high one to C=200 per API 14E. Recommended gas velocities are considered as 50% of corresponding erosional velocities, low is represented by the orange line of the diagram, high by the red line. Recommended max allowable velocities by Norsok Standard P-001 are also presented for comparison (green line on diagram).
α. According to above, allowable max gas velocity under the conditions specified by cnu879 would be 7.4 - 14.7 m/s, versus 28.4 m/s given by Norsok Standard. Indeed, recommended velocities are quite low for high pressure pipe lines.
β. If operating pressure of the gas were 0.2 barg (which could more or less occur in a city distribution network, with no polyethylene pipes), allowable max gas velocity would be 64 - 127 m/s, versus 60 m/s per Norsok Standard.
γ. The lower the pressure the higher the max allowable velocity. Reasonable, since density decreases with pressure (yet density * estim max allowable velocity decreases with pressure).
Recommended gas velocities should report corresponding operating pressure.
δ. Norsok Standard gives much higher velocities for pressures higher than about 15 barg (approaching starting erosional velocities for C=200). For lower pressures it gives a flat value of 60 m/s.
3. Questions to promote clarification of the matter.
"Handbook of Natural Gas Transmission and Processing" gives a method to specify max allowable gas velocity, depending on conditions.
3.1 What is considered as starting erosional velocity in normal NG pipe lines, per API 14E ? Shall we use C=100, or C=200 in the formula (in lb/s/ft2)?
C=100 when there may be condensate, or corrosion? How is it that the gas contains solid particles?
3.2 A flat allowable max velocity at low operating pressures (60 m/s per Norsok standard) seems reasonable to apply in the case of NG pipe line. Can you confirm applicability and recommend flat value? The Handbook of Natural Gas does not seem to mention something similar.
3.3 Any other comment on the above or the "NGvel.xls"?

4. Note: For additional info that could be useful, refer to the links below.
http://www.eng-tips.....cfm?qid=147153
http://www.flowcontr...s-pipe-velocity

Attached Files

•  NGvel.xls   42.5KB   2205 downloads

[ankur2061]

δ. C=100 in most cases. API RP 14E (1984) suggested C=100 for continuous and 125 for non continuous service. In addition C = 150 to 200 may be used for continuous, non corrosive or corrosion controlled services without solid particles present.

The API 14E quote is incorrect. The erosion velocity "C" values as per API 14E, Section 2.5 (a) are for "Gas-Liquid 2-phase lines" and not for single-phase gas lines. In fact API 14E does not even mention anything about erosion velocity for single-phase gas lines. API 14E mentions the following for velocity limitations in single-phase gas lines:

Also velocity may be a noise problem if it exceeds 60 ft/s; however the velocity of 60 ft/s may not be interpreted as an absolute criteria. Higher velocities are acceptable when pipe routing, valve choice and placemenmt are done to minimize or isolate noise.

It is important to note that the title of this section in API 14E is "Sizing Criteria for Single-Phase Gas Lines". This does not necessarily mean that it is also applicable to long-distance gas transmission pipelines.

For solids-free sales gas pipelines, "C" values can be much higher. It is more the pressure drop and the supporting and running the long distance pipeline through a diverse terrain which will govern the line sizing. Refer the link below for some information on "C" values in the erosion velocity formula:

http://www.cheresour...city#entry58720

Regards,
Ankur

Edited by ankur2061, 24 June 2012 - 08:08 AM.

[kkala]

1. Not having access to API 14E, I can say that post No 7, para 1, reflects the writing of "Handbook of Natural Gas Transmission and Processing" , subsection 11.6.1 (Sales Gas Transmission - Line Sizing Criteria). as explained there. There is no mention of two phase flow in this subsection. Exact wording of the relevant point is as below:
"In most pipelines, the recommended value for the gas velocity in the transmission pipelines is normally 40 to 50% of the erosional velocity (Mohitpour et al., 2002). As a rule of thump, pipe erosion begins to occur when the velocity of flow exceeds the value given by Equation (11-22) (Beggs, 1984): Ve = C/ρ^0.5 (11-22)
where Vc is erosional flow velocity, ft/sec; ρ is density of the gas, lb/ft3; and C is empirical constant.
In most cases, C is taken to be 100. However, API RP 14E (1984) suggested a value of C=100 for a continuous service and 125 for a noncontinuous service. In addition, it suggests that values of C from 150 to 200 may be used for continuous, noncorropsive or corrosion controlled services if no solid particles are present".
2. http://www.cheresources.com/invision/topic/10801-c-factor-in-the-erosional-velocity-eqn-as-per-api-rp-14e/ proposes higher values for C to be used in the erosional velocity formula. It refers to two phase flow in "flowlines and pipelines", understood as any gas line (if not, please clarify). The previous limitation "allowable gas velocity = 40 - 50% of erosional velocity" is understood to concern long distance pipelines only.
3. It is improbable that authors of "Handbook of Natural Gas Transmission and Processing" misinterpret API 14E. Probably some condensation of hydrocarbons / water is quite possible in long distance pipelines, even if gas is initially without condensates; so allowable velocity should be based on erosion velocity, even if quantity of formed condensates is minimum. Casual changes of gas composition can also result in condensates. Clarifications on this point would be welcomed. We speak here of condensates formed in the pipeline, not in the Pressure Reducing (and metering) stations.
4. Erosion in gases is accepted to be due to entrained liquids or solids, since increasing velocity of gas (without liquids or solids) will create rather noise / vibrations than erosion. Assumption of condensation could explain the low recommended velocities (say 10 m/s) in high pressure pipelines. Besides it could explain difference to allowable velocity per Norsok standard (for pressures higher than ~ 15 barg).
Influence of solids on erosional velocity is estimated by API 14E for two phase flow, what about same influence for gas without any condensate?
5. In order to estimate NG allowable velocities in long distance pipelines, I think we need answers to the following (after consideration of the above).
5.1 For a gas introduced "dry" to the pipeline, will it usually "create" condensates (water / hydrocarbons) somewhere or not? Water and hydrocarbon dew points may suggest "not", but what happens in practice?
5.1a. If not (i.e. dry gas always), how can we specify max allowable velocity in function of actual density or other parameters? Objective is to have a guide for allowable velocity at various operating conditions, at least in usual case concerning condensates.
5.2 How could we interpret / comment on relevant text of "Handbook of Natural Gas Transmission and Processing" (para 1)?
5.3 Any response to point 3.2 (even assuming two phase), or 3.3 of post No 7?

Edited by kkala, 24 June 2012 - 03:56 PM.

[ankur2061]

3. It is improbable that authors of "Handbook of Natural Gas Transmission and Processing" misinterpret API 14E. Probably some condensation of hydrocarbons / water is quite possible in long distance pipelines, even if gas is initially without condensates; so allowable velocity should be based on erosion velocity, even if quantity of formed condensates is minimum. Casual changes of gas composition can also result in condensates. Clarifications on this point would be welcomed. We speak here of condensates formed in the pipeline, not in the Pressure Reducing (and metering) stations.

Long-Distance Sales Gas Transmission pipelines have water specifications of a maximum of 7 lb per MMSCF as required in the United States . In Canada it is <= 5 lb per MMSCF. Water is a strict no-no in gas transmission lines since it can cause corrosion as well as slugging due to water accumulation. So probability of water has to be ruled out.

Most long-distance pipelines for sales gas run buried. Temperature variations are thus minimized. As long as the temperature in the pipeline is above its cricondentherm value, hydrocarbon condensation is ruled out irrespective of the pressure. Again dropout of hydrocarbons is detrimental to the operation of the pipeline since it can cause slugging and can lead to increased pressure drop thus disrupting the pipeline operation. In most cases the HC dewpoint of sales gas is below -20°C. So once again the probability of some condensation of hydrocarbons in a sales gas transmission pipeline is ruled out. Similar to the water content specification for gas transmission lines, pipeline operators have also defined limits for "liquefiable HCs" in pipelines and these figures are quite low. For a reference to allowable "water content" and "liquefiable HCs" in gas transmission lines in North America refer the link below:

http://www.beg.utexa...angeability.pdf


The conclusion is that sales gas transmission has to be treated as a single-phase flow and not as a "probable" two-phase flow. Also there is an inference that copying from a book does not make it entirely true and one has to do an indepth study of the subject before coming to any conclusions. Engineering just does not work on the theory of probability.

Regards,
Ankur.

Edited by ankur2061, 24 June 2012 - 11:41 PM.

[Shivshankar]

Ankur

Apology for misappropriate post.

Is there any formula or thumb of rule to calculate gas velocity for long distance transmission of sales gas ?

Attaching some useful PPT on Gas Pipelines.


Regards
Shivshankar

Attached Files

•  New Folder (4).zip   732.3KB   1518 downloads

[ankur2061]

Shivshankar,

Bulk velocity at any cross-section of the pipeline is nothing but the flow rate @ operating pressure / temperature divided by the cross-sectional area of the pipe.

v = Q / A

where:

v = velocity

Q = flow rate

A = cross-sectional area of the pipeline

The presentation you have provided has no name for the author. E. Shashi Menon's book "Gas Pipeline Hydraulics" whose reference is given in the presentation does talk about erosional velocity and there is no denying the fact that erosion velocity is a factor to be considered. However, the point is that E. Shashi Menon's book fails to consider that erosion is a factor related to the metallurgy of the pipeline for evaluating "C" factors in the erosion velocity equation. It is obvious that the "C" factor cannot be the same for carbon-steel and stainless steel. "C" value of 100 as provided in Menon's book is far too conservative and not practical in today's context when production economics need to be carefully evaluated from gas-condensate wells. When I mention gas-condensate wells it is gas and condensate as a 2-phase fluid, and not sales gas.

I have myself proposed in post #6, that long-distance sales gas transmission pipleines should not have velocities exceeding 10 m/s. This is based on experience of companies like Shell and considers a variety of factors such as pressure drop, erosion/corrosion, pipeline terrain, operational flexibility, periodic maintenance and the life-cycle cost of the pipeline.

A point raised in post #9 says about pressure reducing stations. Gas transmission pipelines do not have pressure reducing sations along the pipeline terrain, instead they generally have pressure booster stations using booster compressors due to unamanageable pressure drops in long distances of the pipeline. Pressure reducing stations are required only at the terminal or consumer end of the pipeline. The pressure at the start point and the terminal point i.e. the required pressure drop along with the velocity plays a major role in determining the pipeline diameter.

Another important point to note for all new design engineers who have just been introduced to pipeline hydraulics is that a lot of natural gas pipeline hydraulic simulation is done using TGNET software from PIPELINE STUDIO. TGNET is a single-phase gas pipeline simulator and is not meant for 2-phase flow which reiterates the fact that sales gas pipeline needs to be modelled as single-phase and not 2-phase.

Regards,
Ankur.

Edited by ankur2061, 25 June 2012 - 05:15 AM.

[Santoshp9]

Dear All,
Thanks for your value added discussion.

Regards,
Santosh

[Shivshankar]

Ankur,

Thanks for interesting discussion.

I am now clear about when to use Weymouth, Panhandle A & B and Spitz glass equations to calculate single phase gas velocity along with erosion velocity for long distance transmission of natural gas.

In API 14E the gas velocities may be calculated using following derived equation.

v = 60*Z*Q*T / d^2* P

Where,

v = Gas velocity (ft/s)
d = Pipe inside diameter, inches
Q = Gas flow rate MMscfd (at 14.7 psia and 60 °F)
T = Operating Temperature °R
P = Operating presssure, psia
Z = Gas compressibility factor

However, I don't know how this equation is derived ?

and erosional velocity is given as

v(e) = C/ √ρ

Where,

v(e) = Fluid erosional velocity (ft/s)
C = Empirical Constant
ρ = Gas Density (lbs/ft3)

For solids-free fluids values of c = 100 for continuous service and c = 125 for intermittent service are conservative.
For solids-free fluids where corrosion is not anticipated or when corrosion is controlled by inhibition or by employing corrosion resistant alloys, values of c = 150 to 200 may be used for continuous service: values up to 250 have been
used successfully for intermittent service.

Regards
Shivshankar

Edited by Shivshankar, 26 June 2012 - 02:28 AM.

[ankur2061]

Shivshankar,

Equation for gas velocity can be derived using dimensional analysis for the various units used in the equation 2.13 given in API 14E from the basic equation I have mentioned and using it at a reference condition of 14.7 psia and 60°F.

You forgot to mention that erosional velocity is for Section 2.5, "Sizing Criteria for Gas/Liquid Two-Phase Lines" and not for single phase gas lines.

Regards,
Ankur.

[Shivshankar]

Ankur,

You are right it is for section 2.5 for gas/Liquid two phase lines and not for single phase gas lines.

Thanks once again.

Regards
Shivshankar

[kkala]

Below are notes on sales gas pipeline sizing. Questions were asked by kkala in post No 9 and replies given by ankur2061 in post No 10 and other. Comments are by kkala.
1. Q: For a gas introduced "dry" to the pipeline, will it usually "create" condensates (water / hydrocarbons) somewhere or not? Water and hydrocarbon dew points may suggest "not", but what happens in practice?
A: ...The conclusion is that sales gas transmission has to be treated as a single-phase flow and not as a "probable" two-phase flow. Also there is an inference that copying from a book does not make it entirely true and one has to do an in depth study of the subject before coming to any conclusions. Engineering just does not work on the theory of probability.
Comments: Post No 9 clearly indicates this is a question, not a statement. Mentioned derogating hints have no place in an engineering forum, lessening its reliability. Nevertheless they do not make an insult to kkala.
-Following is taken from "New Folder(4).zip" attached to post No 11 by Shivshankar, "Sales Gas Pipeline Part I", section "Single Phase Gas flow".
"Erosional velocity: Higher velocities will cause erosion of the pipe interior over a long period of time. The upper limit of the gas velocity is usually calculated approximately from the following equation:
Vmax (ft/s) = 100/SQRT(ρg (lbm/ft3)).
Usually, an acceptable operational velocity is 50% of the above".
"Pipeline efficiency: In Practice, even for single phase gas flow, some water or condensate may be present. Some solids may be also present. Therefore the gas flow rate must be multiplied by an efficiency factor (E).
A pipeline with E greater than 0.9 is usually considered clean".
I have heard of NG liquids formed along the pipeline and of slug catchers; yet these cases can represent non normal operation (e.g. change in composition spec) resulting in lower gas flow rate.
2. Q: If not (i.e. dry gas always), how can we specify max allowable velocity in function of actual density or other parameters? Objective is to have a guide for allowable velocity at various operating conditions, at least in usual case concerning condensates.
A: gas velocities in transportation of natural gas through long-distance pipelines should be in the range of 5-10 m/s for continuous operation and a maximum up to 20 m/s for intermittent operation...
I would not design a long-distance natural gas transmission pipe line for a velocity of more than 10 m/s normally...
Long-distance sales gas transmission pipelines should not have velocities exceeding 10 m/s. This is based on experience of companies like Shell and considers a variety of factors such as pressure drop, erosion/corrosion, pipeline terrain, operational flexibility, periodic maintenance and the life-cycle cost of the pipeline.
Comments: Above evidently concerns sales gas pipelines without any condensate in it (dry gas), according to answer 1. One would expect gradually higher allowable velocities as operating pressure goes lower e.g. from 70 barg downswards; not a flat 10 m/s. On what pressure this velocity refers to?
Clarification would be welcomed, so that allowable velocity could be estimated for any operating condition.
- An explanation why dry gas allowable velocity is so low at high operating pressures would be also useful.
Erosion is understood not to affect a dry gas pipeline without solids (post No 9, para 4), where allowable max velocity is specified by noise, vibration results, potential corrosion. Economics affect allowable (frictional) ΔP per unit length and may dictate a lower velocity. Allowable max velocity (initially specified) does not seem to depend on allowable ΔP per unit length. Advice on this point appreciated.
3. Q: How could we interpret / comment on relevant text of "Handbook of Natural Gas Transmission and Processing"?
A: ...there is an inference that copying from a book does not make it entirely true and one has to do an in depth study of the subject before coming to any conclusions...
Comments: Placing the question to the forum, could have hopefully made things clearer.
-Text from Shivshankar attachment complies with 50% erosional velocity for sales gas pipelines, too. This concept seems to predict the low allowable velocities at high pressures (say 70 barg), otherwise how could these velocities be explained? Or these 10 m/s correspond to optimum ΔP/unit lenth, while allowable max velocity is actually higher?
4. Q: Any response to point 3.2 (even assuming two phase), or 3.3 of post No 7?
Comment on 3.2, post No7: Answer is pending.
Concerning dry gas, a flat allowable max velocity is anticipated at low pressures (like in Norsok std).
For two phase flow, does API 14E specify a flat max allowable velocity at low pressures? (no mention of it so far).
Comment on 3.3, post No 7. General comments on posts 7, 9, 17 welcomed (numerous, if possible).
- "Handbook of Natural Gas Transmission and Processing", Chapter 3, notes that flow is often multiphase in the raw gas transmission lines from wells (different to sales gas pipelines). Post No 7 is anticipated to be applicable for these multiphase flows (allowable velocity = 50% of erosional) with the revised values of C. Can you confirm or advise accordingly?

Edited by kkala, 27 June 2012 - 04:04 PM.

[kkala]

Comments on post No 12 by ankur2061:
1. Important point of the presentation (attachment by Shivshankar) is that it reports erosional velocity in the chapter of "Single phase gas flow", see post No 17.
2. Pressure Reducing Stations were mentioned in Post No 9, para 3, to clarify that the question does not refer to condensates created in them " We speak here of condensates formed in the pipeline, not in the Pressure Reducing (and metering) stations". So the comment about them is irrelevant.
3. For mentioned allowable velocity of 10 m/s, please refer to post No 17.

[Butterfly]

Thanks for the interesting discussion.

Considering steam, instead of natural gas, I read in some book regarding steam & condensate network design that for pressures between 25-100 bar, recommended velocities are 60 m/s for saturated steam, 75 m/s when superheated. This book is related to industrial uses/processing plants. My question is: can I use this values when there is a steam network with long pipeline distances (10 km) for upstream uses?

If there was undersaturated steam, I would use the erosional velocity formula, with C=100, and an operational velocity about 50% of the erosional velocity, is this right? Is the 40-50% of the erosional velocity a statement taken from API, or recommended practice?

Thanks in advance

[ankur2061]

I have BP guidelines for maximum velocities from the BP document "GP 06-14, Guidance on Practice of Erosion Control" where the velocities for saturated steam and superheated steam is also provided.

BP recommends a maximum velocity of 23 m/s for saturated steam and 38 m/s for superheated steam or v = 180*ρ^-0.5 where ρ = flowing density, kg /m³ whichever is lower.

These values seem to be reasonable from all aspects including vibration and noise due to very high velocities.

Regards,
Ankur.

[shin29]

Thank you all for such a topic.

Sir I work in a Natural gas plant , what more interest me is procedures , codes and standard followd for calculations in piping.

My questions are:

1. What code / standard I should take reference from while assuming max flow velocities in piping?
2. Are there different guidelines for max NG flow through from ultrasonic meter?
3. Which equation is more suitable for calculation of compessibilty of gas or, more precisely, max. MMSCFD for a Given pipe line?

Regards,
Shn

[cnu879]

ankur, Kkala. Shishankar,

Thanks you for sharing valuable information and spending your valuable time.

Regards,
Sriniii

[ElSid]

Great topic and now book marked. Note that if the pipe is in a building or plant, use the code books (e.g. UPC). For the transmission piping ... well, I need to read and comprehend the items above.

NOTE: in the U.S., several companies have their criteria/manuals. I've had to work with Southwest Gas, but they did not "disclose" their pipeline design manual. They supplied the feed to the meter and from there I designed the plant wide pipe. Using the code books made it "easier" for the inspectors.

[scrowder]

Does anyone have a table of C-Factors that is material specific?

I have run into various random statements like these:

 

Presumable based on Ve = C/dm  where Ve is critical velocity in feet/sec,....dm is density of mixture in lbm/ft3

 

Carbon Steel: 100 - 135 (solids free is lesws than 1 lbm per 1000 oilfield bbls of liquid)

13Cr:  C=300

Duplex C=350

 

rgrds

Scott

[ankur2061]

Scott,

 

Not much research has been done in this area. One of the most comprehensive documents related to erosion know to me is by "BP Amoco" titled  "Erosion Guidelines" which provides some values on "C" factors. Below is what they list out for the "C" factor for various materials and flow conditions:

 

CS: a) "C" = 135 if  nominally solids free (solids less than 1 pound of solid per thousand barrel of liquid)

       b) "C" = 200 or Ve = 65.6 ft/s whichever is lower if totally solids free

 

13Cr Steel: "C" = 300 if nominally solids free

DSS: "C" = 350 if nominally solids free

 

Single Phase Liquid Flow:

 

CS: "C" = 250 (under CO2 corrosion and no corrosion inhibition)

13%Cr Steel: "C" = 300

DSS: "C" = 450 if nominally solids free

 

Hope this helps.

 

Regards,

Ankur.

Edited by Art Montemayor, 21 March 2013 - 11:20 AM.
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