Buried Hydrogen Pipeline at Elevated Temperatures 4

[MuscMech]

I'm working on the design of a buried hydrogen pipeline (API-5L X60) that is several miles long. I'm using Caesar II software to evaluate it and have access to ASME B31.1, B31.3, and B31.12. I'm assuming an ambient temperature of 70F (should probably consider using 50F) and the design temperature is set at 180F. I first wanted to see if modeling the pipe as direct buried would have any issues. The results are failure in the sustained and expansion cases and extremely high forces at certain elbows, upwards of 700,000 lbs. Failing in the sustained case may be a separate issue. I followed the process in ASME B31.12 to determine the wall thickness but maybe a thicker wall is required. I have a few questions: 1) Is there an industry accepted practice for reducing the design temperature based on the distance from the source? 2) Is there a good way to determine if the pipe will slip or if soil will hold it in place and not allow it to slide? This could make the difference between a pipeline that is pretty much a straight shot compared to dozens or even hundreds of expansion loops. Any input to these questions or just general insight would be greatly appreciated.

 

[1503-44]

You can make a thermal model and include thermal and heat exchange characteristics of the pipe, product and soil to determine estimated temperature of the pipe at any point and set design temperature accordingly.

Caesar is capable of doing pipe soil interface modeling. Enter the appropriate variables. Usually soil to pipe adhesion and friction is sufficient to stop a thermally expanding pipeline after a certain length of contact has been achieved. Search "virtual pipeline anchor". That distance is often around 300 to 1000 ft, but depends of course on precise configuration, soil strengths and pipe and ambient temperatures. Exposed above ground expansion loops are not practical for pipelines and underground expansion loops are not very effective. Increasing wall thickness to reduce temperature stress does not help, as restraining forces increase directly with the pipe's area of steel. Set wall thickness based on pressure and find acceptable configurations. You may also have to limit degrees of bend, both horizontally and vertically, especially at overbends, in order to prevent thermal overstress, or "pop up" movements. A minimum burial depth may need to be set for overbends.

One of the accepted codes used for design of pipelines transporting hydrogen gas is B31.8, or if in the USA, the legal requirement is to use CFR Title 49, Part 192. There are differences. Caesar has a pipeline code check, so I'd figure out how to switch that feature to on. Generally you must use a pipeline design code if you are not entirely located on company's private property.

 

[saplanti]

Are you going to bury carbon steel bare pipe into soil without external insulation? How are you going to solve external corrosion problem? Will you additionally use cathodic protection?

Are you going to use electrical insulators where the pipe rises aboveground?

What will the buried depth will be in your case? You probably thought about the maintenance issues on the line. It may seem it is cheaper to burry pipe but it may bring all these problems with it. Before making decision you should probably talk to your operators.

I assume you have already considered all of above, I suggest you to consider several change of directions along the pipe route in the soil since the pipe material will be effected by thermal loading (expansion/contraction). At those location you may be forced to use hot bending if the directional changes are sharp. You may be able to try cold bending as well, but this may require special equipment and experience to use.

I suggest you to read C2 technical manual and user manual for buried piping modeling. It is simple if you follow what they say in the manuals. You need to use appropriate number of nodes especially where the pipe goes in/out of soil, change of direction etc.. to be able to see adequate expected results. Otherwise you may be disappointed.

If you know the soil, and the bedding and covering you need to introduce the surrounding soil type into the model, C2 will provide adequate restraining support stiffnesses at node locations of the buried pipe.

The other point is the load combinations, and code evaluation. Again, the manuals give you direction on that. They are different than the aboveground piping load cases for code evaluation.

I hope this is sufficient.

 

[1503-44]

Use or not of corrosion coating was not stated, but obviously considered SOP for buried pipe.
Electrical isolation is not normally required simply by rising above ground.
He has stated that direct burial is the case he is studying.
Once buried and virtually anchored, changes in direction, horizontally or vertically, can introduce unwanted stresses. They should not usually be introduced without necessity, such as paralleling a road, or the need for some reason in maintaining a constant burial depth, or clearance of obstacles.

 

[LittleInch]

muscmech.

your post appears to indicate that you have very little experience of buried pipeline design.

Can you tell us what your role is, your experience and how much help you have available locally as you do not appear to understand the basics of this so I need to know where to begin.

But find out what the OPERATING temperature is as start point. Design temp is often very high compared to operating temp and once you go over about 50C of thermal expansion, buried pipeline stress analysis becomes difficult and needs experienced engineers to design out the issues.

Is this a new pipeline?
Why 80C?

B31.12 was a little used code until a couple of years ago when H2 pipelines suddenly started to be looked at in earnest so not many people are familiar with its workings, but it borrows a lot from B 31.8 and other B 31 codes for the piping side. It is though a complete code as far as I can tell for piping and pipelines.

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

 

[davefitz]

I think increasing the wall thickness will not have significant benefit if the loads are due to thermal expansion, as the load will increase in proportion to the thickness , so the stress will not appreciably change, unless the expansion load is also reduced by movement of the soil or some other fixed boundary. A protected ( ie sleeve enclosed) flex joint might be needed.

Also, the old NASA safety rules for hydrogen piping prohibits underground routing of H2 piping, as its leakage will inevitably lead to seepage into other unpressurized pipes ( sewers, buildings) and fires/explosions in adjacent buildings. They recommended routing in vented trenches or overhead routing wherever feasible. However, I am aware that it has become common to route H2 pipe underground at combined cycle power plants, and in those cases the pipes are sleeved in another pipe when routing near buildings, and extra caution is needed to ensure corrosion from soil is prevented from occurring. My own experience is that this corrosion of CS H2 pipe is the most likely failure mode of UG H2 piping.

"...when logic, and proportion, have fallen, sloppy dead..." Grace Slick

 

[1503-44]

You may also note the following here,

https://www.jdsupra.com/legalnews/federal-hydrogen-regulation-in-the-54947/

PHMSA

PHMSA’s mission is to protect human health and the environment by promoting the safe transportation of energy and other hazardous materials by creating national policy, setting and enforcing industry standards, and conducting research.30 PHMSA currently regulates approximately 700 miles of hydrogen pipelines via 49 C.F.R. Part 192.31. These regulations are primarily focused on natural gas, but the definition of gas under this provision includes “flammable gas”, which brings hydrogen into play.32 However, due to the fact that the primary focus of these regulations is natural gas, certain characteristics of hydrogen are not necessarily fully contemplated in some of the existing regulations’ design requirements. Nonetheless, in light of PHMSA’s goals and the intent of its regulations, PHMSA currently is conducting research regarding hydrogen’s effects on steel pipelines.33

PHMSA does administer some regulations that more specifically focus on hydrogen. For example, 40 C.F.R. §§ 173.230, 173.301, and 173.302 regulate hydrogen in transportation. (My note: Pretty sure that this applies only to transport in pressurised containers)In addition, 40 C.F.R. § 173.230 imposes certain requirements for the design, filling, and marking of hydrogen fuel cells, and 40 C.F.R. §§ 173.301 and 173.302 impose general requirements on the transportation of compressed gases, including compressed hydrogen. These regulations provide some guidance on the use of hydrogen, but fall short of creating a comprehensive regulatory regime that will guide the development of the entire industry.

 

[saplanti]

The following gives substantial information about the H2 pipelines. Please check the material requirements in addition to others for the pipelines. The material that you intended to use is not acceptable by this document.

https://h2tools.org/sites/default/files/Doc121_04 H2TransportationPipelines.pdf

Here is another.

https://corridoreis.anl.gov/documents/docs/technical/APT_61012_EVS_TM_08_2.pdf

 

[1503-44]

Good catch.

 

[MuscMech]

I'll see if I can answer these all in one go. I probably shouldn't have included the question alluding to a pipeline virtual anchor. The pipe would be wrapped and would have cathodic protection. By direct buried I just meant that it would not be insulated or installed with a secondary containment system such as Perma-Pipe Multi-Therm. I had already modeled it in Caesar II using the underground pipe modeler. That's where I came up with the high stress values and high forces at elbows. I didn't mention increasing the wall thickness as a way to reduce the expansion stress. I offered it as a solution to the Caesar sustained stress being too high, but even when I asked it didn't make sense to me. I think I found out what the issue was there. When calculating min wall with B31.12, you use the specified minimum yield strength. We are specifying API-5L X60, Class 1, Division 2. That min wall results in 0.834". Caesar uses B31.3 to evaluate API-5L X60 with an allowable stress of 25ksi. I think the pipe is failing in the Caesar sustained case due to this difference in how the two different codes are applied.

To share a little of my background, I'm a consultant doing work primarily in the power generation industry. I have around 14 years of experience, probably around a quarter of that time has been dedicated to doing pipe support design. The majority of my pipe support design has been in high energy piping systems such as main steam, cold reheat, and hot reheat, but also boiler feedwater, auxiliary steam, etc. My experience in piping below grade has either been piping in trenches, piping with secondary containment systems, or cold piping. I have never designed for a system that is miles long, much less one that is also at slightly elevated temperatures.

I don't know what the operating temperature is or what the design temperature is based on. We are in the very preliminary stages and the operating temperature was left blank on our client's line list. This will be a new pipeline branching off an existing system.

 

[saplanti]

Could this sustained load case failure be the result of the modelling of buried pipe?

C2 thinks that the buried pipe is vertically supported in the soil. If you look at the distance between nodes for buried piping in C2 buried pipe models, they are a lot longer than the support distances for aboveground piping model.
When buried pipe assigned between certain nodes C2 normally eliminated the gravity for those members due to the full vertical support. In your case this may be missed with the modelling mistake. You need to follow the instruction of C2 manuals to overcome that. Perhaps you may send your model and ask for Coade’s help for the model. Additionally you may be able to find some help from the following forum.

http://forums.coade.com/ubbthreads/ubbthreads.php?ubb=postlist&Board=1

 

[1503-44]

Hard to believe there is no 31.8 code check in Caesar II. And I don't understand how full support for gravity loads between nodes could cause overstress.

The wrong allowable stress certainly does not help. And not discounting the possibility of a modelling mistake, I think the fail is basically due to the 180°F temperature, pretty much on its own, however you do not mention the design pressure. It is difficult to pass the combined stress allowable for any buried 180F+ pipeline with wall sized for pressure in accordance with DF >= 0.72 DF. I'd try reducing the DF for pressure to 0.60, or lower, set the wall thickness on that basis and run again.

 

[LittleInch]

My understanding of ASME B 31.12 is that anything above X52 isn't worth doing as the code applies factors which essentially reduce the stress to X52.

Also buried pipelines normally use bends, not elbows, with radius starting at 5D and gradually increasing until your stresses reduce.

But temperature difference between installed temp and operating temp is your issue. If you don't get that below 50C you're in a world of pain. Also if there is a buried tee connection that is also a difficult thing to get right.

But I think you need to ask or find someone who's done C2 buried pipeline work to check your inputs as they don't sound like you really know when to change the default settings or find the right inputs for the soil springs etc. Maybe you do, maybe you don't, but an input check is the first thing I ask for when the results are not what you expect.

Buried stuff in C2 is quite different and you cant apply the same logic or even the same fittings.

The B31.3 thing is an error somewhere as it definitely checks against the main pipeline codes. Not sure if B31.12 is in there - ask Coade.



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

 

[1503-44]

Stress reduction for H2 effect?

 

[davefitz]

Don't forget that due to the max temp of 180F, you have exceeded the initial temp for SCC in some types of SS piping ( 140 F), and stresses above 12K psi will also initiate SCC in some materials. The soil should be sampled to ensure no residual chlorides ( if the location was underwater 1 E6 yrs ago) exist. Not a bad time to call a metallurgist.

"...when logic, and proportion, have fallen, sloppy dead..." Grace Slick

 

[goutam_freelance]

I hope you have gone through B31.1 'NONMANDATORY APPENDIX VII PROCEDURES FOR THE DESIGN OF RESTRAINED UNDERGROUND PIPING'

Engineers, think what we have done to the environment !

https://www.linkedin.com/in/goutam-das-59743b30/

 

[LittleInch]

Goutam,

You clearly know b31.1 well but that is not a pipeline code. It might have some good points but you need to be very careful about extending a piping code to pipelines.

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

 

[1503-44]

B31.1 is actually extremely useful in regard to principles of, behavior and analysis of UG pipe and general enough to apply to all codes ... within reason.

 

[davefitz]

Large temperature growth range excludes use of SS for UG H2 pipe, high coef of thermal expansion and low yield stress worsens stress issues, in addition to SSC issues.Cost is major issue.

"...when logic, and proportion, have fallen, sloppy dead..." Grace Slick