Smart questions
Smart answers
Smart people
INTELLIGENT WORK FORUMS
FOR ENGINEERING PROFESSIONALS

Member Login




Remember Me
Forgot Password?
Join Us!

Come Join Us!

Are you an
Engineering professional?
Join Eng-Tips now!
  • Talk With Other Members
  • Be Notified Of Responses
    To Your Posts
  • Keyword Search
  • One-Click Access To Your
    Favorite Forums
  • Automated Signatures
    On Your Posts
  • Best Of All, It's Free!

Join Eng-Tips
*Eng-Tips's functionality depends on members receiving e-mail. By joining you are opting in to receive e-mail.

Donate Today!

Do you enjoy these
technical forums?
Donate Today! Click Here

Posting Guidelines

Promoting, selling, recruiting, coursework and thesis posting is forbidden.
Jobs from Indeed

Link To This Forum!

Partner Button
Add Stickiness To Your Site By Linking To This Professionally Managed Technical Forum.
Just copy and paste the
code below into your site.

DEEPBLUE76 (Mechanical) (OP)
12 Jan 07 9:09
Can anyone help me out with a detail procedure or may be a spread sheet to calculate the Pipe thickness for underground pipes as per AWWA need it very urgently please help pipe material API 5L
Helpful Member!(2)  rconner (Civil/Environmental)
12 Jan 07 11:20
I would recommend you contact the manufacturer of the pipe and perhaps also obtain a copy of AWWA Manual M11, Guide for the Design and Installation of Steel Pipe (beyond this I know some large pipe manufacturers e.g. AMERICAN Spriralweld have much online information available see e.g. at http://www.acipco.com/aswp/pdfs/ASWP2-Design.pdf, and given of course appropriate input from customers they will also perform such analyses and furnish the results of the analyses utilizing their own proprietary programs to customers.)  There are potentially a lot of design criteria to consider, and the calculations can be quite voluminous in some projects.
GregLamberson (Petroleum)
13 Jan 07 6:59
As rconner pointed out, there are many factors, including system pressure, service, corrosion allowance (if any), pipe grade, design factor, and diameter.

It is generally a fairly simple calculation once you have the relevant data.  It can be complicated by site conditions and service and as rconner pointed out depending on the criteria can be large.

Greg Lamberson
Consultant - Upstream Energy
Website: www.oil-gas-consulting.com

GSTeng (Mechanical)
14 Jan 07 11:09
In my expereince underground pipe (as long as it is not very deep) is no different from calculating above ground pipe. Since the highest pressures are on the inside of the pipe (unless it is an atmospheric or nonpressureize pipe). There are cases where underground pipe needs to take into consideration exernal forces.

Case in point. A Pipeline was installed under a lake here a long time ago. While working on the end of the pipeline many years later the lines was blown down. 500psig gas line at the bottom of a 100' deep lake. When the pipeline depressurized for the first time in 20-30 years it collapsed creating a very big problem and big mess. External forces on the pipe were a very big factor here and they needed to be considered when the pipeline was at Atmospheric pressure.

This may not apply to your application but it brings to light things that need to be considered.
GregLamberson (Petroleum)
14 Jan 07 11:32
If this is a standard pipeline handling crude/product or gas (this is all I work with), then the calculation for wall thickness is:

WT (inches)=(P x D)/(2 x SMYS x design factor x T x E), where:
P = design pressure, psi
D = nominal diameter, inches
SMYS = pipe grade, i.e. X60 = 60,000 in psi
Design Factor = depends on your class location, Class 1 = .72, Class 2 = .60, Class 3 = .50, and Class 4 = .40
E = joint factor (normally 1 on standard cross coutnry pipelines)
T = temperature factor (normally 1 on standard cross country pipelines)

Again, the above is for piplines installed according to B31.4 and B31.8 using API 5L pipe.  If you have any factors that are different from the above, you may need to do some more investigation or throw it back on the forum and we can see if we can help.

Greg Lamberson
Consultant - Upstream Energy
Website: www.oil-gas-consulting.com

GregLamberson (Petroleum)
14 Jan 07 11:49
Oopps, forgot to mention.  Once you get the wall thickness calculated, normally you would go to API 5L and look at the next thickest diamter to use, for example, you calculate 0.269", you would round up to 0.280".  

This is unless you are looking at a very long pipeline and then you can save some money on tons of pipe by requesting a special rolling at your required wall thickness but I suspect yours will be fairly small quantities?  If so, stick with the standard wall thicknesses.

Greg Lamberson
Consultant - Upstream Energy
Website: www.oil-gas-consulting.com

BigInch (Petroleum)
14 Jan 07 18:20
rconner, nice reference and worth a star.

DeepBlue, you need the yield strength of the 5L pipe.  There are a few grades, 5L-B, X42, X52, X60, X70 ?? What do you have?

Most engineers look at the design of steel pipe without evaluating all of the possible solutions.  

Using AWWA guidelines for design, a 48” diameter pipeline with 0.240 wall thickness would withstand an earthload of 20 ft. of cover.  To get to 27 ft of cover you would need to increase the wall thickness to 0.500” wall thickness.

C-200  Steel Water Pipe applies to 6 inches and larger.

AWWA Steel pipe wall thickness formulas for internal pressure design only is,

t = Pw*D/2/S/F
Pw = working pressure psig
D = outside diameter inches
S = yield strength of steel API 5L Grade ?
F = design factor  AWWA usually is 0.50

Where surge pressure is > 1/2 Working pressure the formula changes and P = (Working pressure + Surge Pressure)

rconner's reference has what you need for burial stresses.

BigInchworm-born in the trenches.
http://virtualpipeline.spaces.msn.com

zdas04 (Mechanical)
14 Jan 07 20:31
GSTEng,
In your example, the pipe was not laid under the lake, the dam was built many years after the pipe was laid and the lake filled up on top of it--Gas Company of New Mexico had some defeciencies, but I don't believe they would have missed that one.

David Simpson, PE
MuleShoe Engineering
www.muleshoe-eng.com
Please see FAQ731-376 for tips on how to make the best use of Eng-Tips Fora.

The harder I work, the luckier I seem

GSTeng (Mechanical)
19 Jan 07 17:29
zdas04,

You are right the pipe came first and then the lake, and you could probably tell the story better than I did, but the moral is still there, and I guess it applies more to the builders of the Dam than the pipeline. Thanks for the correction.
zdas04 (Mechanical)
19 Jan 07 17:59
Sorry about bringing it up, I just keep hearing about how they laid the pipe under the lake and it collapsed and it grates.  Have you seen the crumpled beer can that the pipe became?  It used to be in the conference room at Milagro Plant.  It's pretty cool.

David
DEEPBLUE76 (Mechanical) (OP)
19 Jan 07 22:09
people i have one mre query, AWWA M11 says when calc. thickness on operating press. the design stress should be 50% of the minimum yeild strngth of steel and while calc. thickness for operating + transient/surge pressure it should be 75% of the yeild strength of steel
i want to know the reason for the above statement. can u help me out.
BigInch (Petroleum)
20 Jan 07 4:17
I think, if you look closely, the AWWA method does not require that surge pressure be included at all in the thickness calculation AS LONG AS surge pressures are LESS THAN 50% of the normal operating pressure.  

The way the above works with the wall thickness calculation is that the 50% safety factor can handle surge pressures up to where surge pressures are 50% of the normal operating pressure.  

At surge pressures higher than 50% of normal operating pressure, AWWA no longer considers that the 50% safety factor is adequate, hence requires that additional wall thickness must be provided.

BigInchworm-born in the trenches.
http://virtualpipeline.spaces.msn.com

DrillerNic (Petroleum)
26 Jan 07 7:55
ZDAS- I'd never heard of this pipeline under a lake collapsing due to external loading, but even if the pipe was first, I would have thought for an unusual operation like the first blowdown in 20years, the operators would have done some due dilligence and checked stuff like "can the pipeline, as it is now, withstand the blowdown?"
zdas04 (Mechanical)
26 Jan 07 10:09
DrillerNic
The line was pretty long with some block valves so that compressor problems didn't require a blowdown and new tie-in's happened upstream of the compressor stations.  The type of gas that it carried wasn't prevelent in the middle of the line (i.e., they were picking up conventional gas in New Mexico and processing it in Colorado, the part of the line that failed was going through some very prolific CBM acerage with very little conventional gas).  There just never was a compelling reason to blow that much high-pressure gas to atmosphere.  It really isn't that uncommon.

David
rconner (Civil/Environmental)
26 Jan 07 17:55
Procedures for analyzing effects of vacuum and buckling due to external head/pressures etc. have been available for many years in the AWWA M11 manual applicable to water pipes (and programs based on same) I mentioned earlier, to be applied with appropriate input where applicable.  Seeing the discussion that has arisen since, I feel compelled however to mention a couple other things.  The case study talked about above sounds interesting, but I think (particularly considering the thousands of mileage out there) that buckling problems of buried pipes at least with the high long-term elastic moduli/stiffness of most common sizes of steel pipe (or even greater stiffness like ductile iron) are rare.  
However, some contemporary and growing applications that should perhaps also be mentioned are horizontal directional drilling (HDD) or other very deep trenchless installations, where increasingly larger pipes might well be subjected to high external fluid pressures of drilling fluids, grouts, and or groundwater etc. by virtue of the profiles/equipment/procedures etc. sometimes used.  I recall an ASCE Pipeline Division paper I attended several years ago (presented incidentally by the engineer who was posthumously awarded the Stephen D. Bechtel Pipeline Engineering award last year) wherein some buckling case-study experience was presented.  In a very deep HDD crossing involving I think a few thousand feet of larger sized oil or gas pipes (I think with not great wall thickness as a result of the use of high yield strength steels), after much preparation, work and some fanfare associated with such work in that area then an assembled entourage and dignitaries were treated to the emergence of the line pulled out onto the receiving bank unfortunately inverted flat as a flitter.  Apparently fearing that the line had been somehow creased bearing on some hidden piles that might have been buried in the area, the contractor repeated the whole shooting match with some new pipe and trajectory.  The new line unfortunately also emerged flattened on the far bank.  I think they eventually repeated the installation a third time with a little thicker pipe and were finally successful.  The pipe was apparently crushed repeatedly somewhere in the deep profiles and continually from that point on until the pull stopped, by the combined effects of external pressure and whatever ovalization effects that I believe are inevitable in bending a long, circular cross-section rigid-welded pipe beam in a deep profile.  I guess in presenting/publishing this paper, the engineer was doing what he could to avoid further repetition of such a fiasco.  
It might also be helpful to mention that at least by some authorities, buckling or ring instability resistance is dependent on an elastic modulus and effective stiffness of the pipe (thus dependent on long-term elastic modulus, or at least a modulus appropriate/effective to the duration of buckling load application), not on the yield strength or shorter-term stiffness of a pipe material.
Everyone have a great weekend.             
BigInch (Petroleum)
26 Jan 07 21:00
If I had to take a shot (in total darkness), it might have been a buckle initiated by inadequate bouyancy control.  Once an inward buckle occurs for any reason, it will tend to progress at reduced energy.  Most usual gas pipeline wall thicknesses should take somewhere around 300 to 400 feet of water before collapse stresses get significant.

BigInchworm-born in the trenches.
http://virtualpipeline.spaces.msn.com

stanier (Mechanical)
28 Jan 07 16:37
Suggested reading on the subject is by the master Timoshenko. Take the codes and stadnards as guides but go back to first principles "Theory of Plates & Shells". You may need to brush up of your differential calculus.

Geoffrey D Stone FIMechE C.Eng;FIEAust CP Eng
www.waterhammer.bigblog.com.au

rconner (Civil/Environmental)
29 Jan 07 11:23
BigInch, I believe the pipe initially involved in the incidents I referred to was unstiffened (FBE coated) 30 inch X-65 steel gas pipe (with about a .32" wall).  It was claimed the pipe was very carefully ballasted for HDD installation with a smaller internal pipe and a metered flow of water into same.
The design formula that is suggested for collapse of an (unburied)  steel pipe with "External Fluid Pressure-Uniform and Radial", at least per M11 is:

Collapse Pressure = 50,200,000(t/d)^3   [with units in compatible psi and inches etc.]

[Note:  This formula was presented by Stewart, is reportedly at least slightly more conservative than that developed by earlier Timoshenko, and thus accounts to some extent for some manufacturing variations etc. in steel pipe.]

I calculate for the input parameters this collapse pressure would be less than 61 psi or ~140 feet of clear water head.  While that particular HDD crossing was not quite that deep (apparently it was slightly less than 120 feet at its deepest, middle point), unfortunately this pipe was apparently, as is the nature of at least some HDD business, surrounded by a significantly more dense fluid (drilling fluid and native soil cuttings etc., that increased the external pressure on the pipe).  While the results by different forensic analyses with some different assumptions/procedures etc. were apparently at some point in discussion close enough to provoke some differences of opinion, let’s just say that with what kind of things go on pulling in a fully-welded string of pipe and subsequent operation there does not appear to be a whole lot of security/safety factor for such a gas pipe!  They reportedly also did some kind of further research that showed that the collapses were beginning precisely at the deepest point in the line.
The Contractor involved was “provided” a new string of heavier pipe that was subsequently successfully installed, and the pain of the cost of new piping was reportedly off-set at least a little by the salvage value of the mashed steel piping.

However, I guess it is quite possible what you say is true with regard to external head capabilities if the same steel pipeline were instead buried in a good quality soil envelope, as it is known (I think found by notable researchers who followed stanier’s venerableTimoshenko) that pipelines are some stiffened against buckling/collapse by at least good, firm bedding.  AWWA M11 provides a different formula for buckling analyses of buried pipes, that takes into account the quality of bedding support (and also provides for direct input of a specific level of vacuum if anticipated in service (that of course can have the tendency to increase external pressures beyond simple elevations etc.)      
FLinTX (Civil/Environmental)
29 Jan 07 12:33
Ok that is for underground pipe installation, what about for above ground (aerial crossings) with steel pipe?, any ideas?
rconner (Civil/Environmental)
29 Jan 07 17:50
FLinTX, I wasn't exactly sure what kind of "ideas" you were looking for, but I tried to explain in my last post above that the specific collapse formula I copied from M11 was per my understanding for pipe without bedding support or "unburied" (which sounds basically like what you are talking about).  The design buckling equation for buried pipes (that I did not reproduce there) is longer/more complicated.
However, if your line is perpetually "aerial" and cannot be submerged etc., it sounds like the most differential external pressure you might have on same would be whatever level of vacuum if any you might develop on the line in all operational/non-operational modes (you would want to make sure whatever pipe thickness you choose perhaps for other criteria is satisfactory with the security level you desire for that level external collapse pressure condition, per the formula).

DEEPBLUE76, minimum AWWA M11 design criteria in fact has a 2.0 safety factor considering design operating pressure vs minimum yield strength of the steel. M11 also has a lesser (1.33) minimum safety factor on the sum of operating plus transient/surge vs yield strength of the steel as your numbers infer (perhaps with some thinking that a very brief transient event might be considered a little less needing of high safety factor than an inexorable load on the pipe exerted on same in perpetuity?)
This is however different (arguably less conservative) than the AWWA design method for ductile iron pipe, wherein a hypothetical net thickness is chosen that gives at least a safety factor of 2.0 on the sum of water working pressure plus surge, and then a further service allowance of .08" (additional safety factor) is added to that thickness to establish the minimum manufacturing thickness.  For AWWA ductile iron pipe, the true safety factor vs total design internal pressure (including surge) is is thus substantially greater than 2.0.      
  
BigInch (Petroleum)
30 Jan 07 4:35
RConner,

OK, makes sense.  My estimate was made for offshore installations where X52 is usually a good maximum value to prevent exactly what happened above.  The extra wall thickness needed for X52 helps collapse pressures and the high installation loads from the stinger tensioners often leaves about a 400 ft depth margin before collapsing stress is reached.  With that poor D/t ratio, I can see where it could very easily have been an external pressure collapse.  The LOWER D/t limit for most pipelines is around 100, (ASME B31.8 has a limit, but I don't recall the exact value right now) for which a thicker wall thickness is usually needed for common internal pressures.  Using the X-65 would give even a thinner wall for pressure than X52 or X60, so it looks at first glance exactly like it was designed only for internal pressure and NO engineer checked it for external pressure collapse!


BigInchworm-born in the trenches.
http://virtualpipeline.spaces.msn.com

stanier (Mechanical)
30 Jan 07 21:07
Australian standard for buried pipe gives a safety factor of 2.5 for instability due to buckling. If the soil is weak the Fs is the same.

As for aboveground pipe the external pressure will not be as for this original case and could not exceed that of full vacuum.

Many engineers out there select pipe based on hoop stress alone. I think that is pretty risky. This particulalry so as in there ignorance they dont do a surge analysis. But that is another subject.

Geoffrey D Stone FIMechE C.Eng;FIEAust CP Eng
www.waterhammer.bigblog.com.au

Reply To This Thread

Posting in the Eng-Tips forums is a member-only feature.

Click Here to join Eng-Tips and talk with other members!

Close Box

Join Eng-Tips® Today!

Join your peers on the Internet's largest technical engineering professional community.
It's easy to join and it's free.

Here's Why Members Love Eng-Tips Forums:

Register now while it's still free!

Already a member? Close this window and log in.

Join Us             Close