Peoples,

I am due to stress some pipe work containing
Crude oil @220c and 20barg code:B31.3

Are there any particular recomendations,
special conditions or tecniques i should be aware of when stressing such pipework?

If so, are these given in stds or codes that i can study?

The client seems ignorant of such matters.

An example of such is to ensure the seal tightness of flanges due to the flamibillty of the (Gas) present in crude oils.

Comments appreciated.

Wow somebody had better figure out which code is in force... and have that agreed upon by all parties before the start of design work.

Sir,
You mis-understand.

the piping code is b31.3
and is well in force

perhaps i should have said standards or guidlines.

i am just after any 'tricks of the trade'regarding crude oil if applicable
similar to the diers studies carried out for relief systems

if my original question is inappropriate i will remove it from this forumn.

I was hoping for a positive response,
especially from the Texas community.

regards

T.J.N

I think that you are wise to ask for any "lessons learned" form the community. The only issues that immediately enter my mind with hot crude are these:

What is the Ph of the crude? We have been using sour (high acid) crude lately in our East Coast refineries because the good stuff is getting expensive and/or unavailable. The problem is with the piping coming from the furnaces to the combo/crude unit and to the coker. At certain temperatures this crude will eat 5 or even 9 chrome alloy pipe quickly (some abrasion from in-pipe coking products may also occur). We have been changing out carbon steel pipe with ASTM 312 tp. 317 stainless to solve (or slow down) this problem. The stainless has a 25 percent greater coefficient of expansion and that usually finds you with more pump loading and therefore the need for more creative loops and restraints. You probably should try to limit the number of in-line flange connections and do a flange check ("equivelent pressure" due to moments at the flange pair) on the flanges that you MUST live with.

You might also want to have a look at the B31.3 Appendix on Safeguarding.

Can't think of much more.

Regards, John.

Thanks!
Erosion and corrosion of the pipe wall within the plant is periodically checked by radiographs for damage and wear.

The quality of crude is good so the acidity is low and therefore Carbon steel pipework has been used from day one.

Please advise on this:
It seams that the existing pipework/system we are tying into will probably have some wear due to it being there from 1960. Radiographs of key wear points are being taken and i can reduce the pipe wall thickness value in Caesar to match.

However, i am worried about the heat exchangers.
Is wear also problem with these? Should i de-value the nozzle allowables in line with the reduction in pipe wall thickness?.
The stiffness/strength ratio of the nozzle wall will be difficult to judge.

My solution is to model the system in a worst case senario with minimum wall thichnes's and to
stay well within the allowables given.

Comments appreciated.

I suggest you enter the wall loss as corrosion in CAESAR II and set the configuration to "All Cases Corroded". In this way, your loads will be based on full wall but all denominators in stress calculations will reflect the current, corroded thickness.

Keep in mind that B31.3 is a "new design" code. Para. 300(c)(2) says: "This Code is not intended to apply to the operation, examination, inspection, testing, maintenance, or repair of piping that has been placed in service."

It appears that you are embarked not just upon the path of new design but rather in a separate and complicated field known as "fitness for service" This engineering specialty is practiced only by the most experienced practioners in the field and is not a subject that should casually be delved into....

I quote from another web site...

Fitness for Service Evaluation
Fitness for Service is defined as the ability to demonstrate the structural integrity of an in-service component containing a flaw. The rapidly becoming standard for conducting fitness-for-service assessments is API 579, Fitness for Service. API 579 describes standardized fitness-for-service techniques for pressurized equipment used in industry and supplements the inspection and assessment techniques in API 510, API 570 and API 653.

Fitness-for-service assessments provide useful economic and safety benefits to end users and operators including: (1) ensuring the safety of plant personnel and the public while older equipment continues to operate and (2) helping to optimize maintenance and operation of existing facilities to maintain the availability of older plants and enhance long term viability. The procedures can be used for evaluation and re-rating of pressure vessels designed and constructed to the ASME Boiler and Pressure Vessel Code; piping systems designed and constructured to the ASME B31.3 Piping Code and aboveground storage tanks designed and constructed to API 650 and API 620.

Typical scenerios requiring a fitness for service assessent include:
Assessment of equipment for general metal loss;
Assessment of equipment for local metal loss;
Assessment of equipment for brittle fracture;
Assessment of equipment for pitting corrosion;
Assessment of equipment for blisters and laminations;
Assessment of equipment for crack-like flaws;
Assessment of fire damage;

See http://www.hghouston.com/services_4.html or do a google look up of API 579...

T.J.N

I think you are going to have to quantify the condition (effective corroded wall thickness for starters) of the existing equipment and piping via NDE methodologies you describe. Since your plant apparently does have a surveillance program in place the HX walls and nozzle walls should have been measured periodically and recent data should be available.

If the same (similar) materials (carbon steels) have been used throughout you can expect rates of corrosion similar to those of the piping. Clearly you will have to make some allowance for the loss of material thickness in the HX shells and nozzles (and the internals). Any Hx handling Crude since 1960 does not owe you much more service!! Have a look at those shell thicknesses, you might want to derate and reset the SRV's (see NBIC-23 for derating).

Perhaps after quantifying the material thicknesses you would want to run a CAESAR II WRC 107 analysis of the HX shells/nozzles.


Good luck and best regards, John.

Wise words Gents.
Thank you very much.
The advice given has been very valuble.

I am aware of my limitations.
I am NOT a vessel engineer so i intend to stay well away from assesing the H/X

What we will do is to run some preliminary calcs to ensure the loads are reasonable on a fully corroded H/X and advise the client that a full inspection/assement of the H/X system is in order.

On a second note, the H/X material ASTM A201B is no longer in use (superseeded by 515)

Do you any of you guys have the basic data for WRC 107 Calcs?.

ASTM are sending a copy of it in the post but i am pushed for time


Regards Tim.

If you can't find S values you can derive them based upon B31.3 para 302.3.2