Which code is more applicable to an oil/gas production pad piping

[engr2GW]

Hi,

The kind of wellhead I see/work around is typically a 200'-500' by 200'-500' pad and inside it are wellheads flowing to high or low pressure gravity separators, gad production unit (which is a pack of indirect line heater connected to a horizontal separator), heater treaters (emulsion treaters), and then gas flowing from the afore mentioned to the gas meter then to the gas gathering lines. The water flows to the water tanks and the oil flows to the oil tanks. We may sometimes have compressors for VRU, flash gas, booster, or gas lift.

My thought is, although ASME B31.3 is for refineries and chemical plants, it is the piping code that best applies to the production pad described above, and then the lines outside the pad for gas and liquid gathering can be goverened by ASME B31.8 and B31.4 respectively because these are only for pipeline/gathering lines?

Is that a good assigning of the pressure piping code? If not, is there any other pressure piping code that best applies to the production pad described above?

Thanks a lot.

 

[if7005]

Usually from choke-valve up to block valve before barred-tee, B31.3 applied.

 

[engr2GW]

thanks if7005,
I'm guessing that "from choke-valve to block valve before barred-tee" encompasses the begining of the flow ling in from the well head to just down stream of the production equipment right?

i.e. what kind of equipment (if any) do you have down stream of the block valve/barred T, or is it just pipeline there from?

Thank you.

 

[BigInch]

It must be my night to quote codes...
Actually even farther than the block valve...

B31.8 - P 802.12 -ss(f)

This Code does not apply to,

(f) wellhead assemblies, including control valves,
flow lines between wellhead and trap or separator, offshore
platform production facility piping, or casing and
tubing in gas or oil wells. (For offshore platform production
facility piping, see API RP 14E.)

B31.8 has nothing to do with anything not concerning "Transportation" of gas, ie. no flow lines, gathering systems, which go up to the trap or separator, oil refineries, or natural gasoline extraction plants.

B31.8 does cover dehy main gas stream piping, and all other processing plants installed as part of a gas transmission system, gas manufacturing plants, industrial plants, or mines, as described in (d).

B31.3 does not specifically state that it covers well piping and flowlines, although it is often applied to these assemblies and pipe connections when other specifications are lacking.

B31.4

400.1.1 This Code prescribes requirements for the
design, materials, construction, assembly, inspection,
and testing of piping transporting liquids such as crude
oil, condensate, natural gasoline, natural gas liquids,
liquefied petroleum gas, carbon dioxide, liquid alcohol,
liquid anhydrous ammonia, and liquid petroleum products
between producers’ lease facilities, tank farms, natural
gas processing plants, refineries, stations, ammonia
plants, terminals (marine, rail, and truck), and other
delivery and receiving points. (See Figs. 400.1.1 and
400.1.2.)

Once off the lease facilities, B31.4 can cover liquid lines according to the diagram supplied in the code showing coverage from a connection at the well, or production facilities, somewhere within the lease.

It is not uncommon for onshore gathering systems in the US to be entirely unregulated.

Propritary company standards often fill the gap for well heads and flowlines, unless they are offshore, in which case API RP 14E is applied.

We will design everything from now on using only S.I. units ... except for the pipe diameter. Unk. British engineer

 

[Duwe6]

B31.3 is indeed the most applicable, IMHO. However, with the pressurized gas and the close proximity of workers, I would use the Visual Inspx and NDT rate of B31.3 Class "M".

Would not designate it Class M, just inspect at that increased rate over "Normal Fluid Service".

 

[BigInch]

Well said.

We will design everything from now on using only S.I. units ... except for the pipe diameter. Unk. British engineer

 

[zdas04]

You can find a quote in B31.3 that is similar to the ones that BigInch provided above. B31.3 explicitly does not apply to well sites. ASME does not cover well sites at all (except pressure vessels that come under BPVC). API doesn't have piping codes. If your company does not have internal standards (many do, many don't) then it comes down to engineering judgement. My judgment says that I will weld according to API 1104 and design according to B31.8. If a client requires B31.3 then I'll design to it, but every single decision results in exactly the same material specification as it would have been under B31.8 and the design cost approximately doubles.

I was an expert witness in a personal injury case once where the plaintiff claims he was injured because the well site was not built to industry standards. The plaintiff lost because the defendant was able to show that there is no industry standards that apply between the wellhead wing valves and the upstream flange on the well site meter. If there is no well site meter (as is common on casinghead gas systems on stripper wells), then no code applies to the gathering line either. If there is a well site meter then the gathering line comes under B31.4 or B31.8.

I can't find anything in B31.3 that admits jurisdiction over well sites.

David

 

[DrillerNic]

"You can find a quote in B31.3 that is similar to the ones that BigInch provided above. B31.3 explicitly does not apply to well sites. ASME does not cover well sites at all (except pressure vessels that come under BPVC). API doesn't have piping codes. If your company does not have internal standards (many do, many don't) then it comes down to engineering judgement.."

And that's why when I was working onshore West Africa I saw gathering systems and flow lines that were made of tubing, laid in a ditch next to the wellpad access roads....

 

[blacksmith37]

I have been retired awhile , but I would have hoped API would have written something for surface facilites by now. Years ago , I saw 4140 used for welded pipe work at gas well sites in LA : there is clearly a need for standardization.

 

[zdas04]

DrillerNic,
I think that is a different issue (I once saw a 3/4 inch solid copper bar in a fuse holder on a platform in the Gulf of Suez, no code in the world would have allowed that). The industry has pretty much circled the wagons that offshore platforms should be built to B31.3. Where the API stops and the ASME starts is sometimes an issue (I talked to an Engineer with a major a few years back that wanted to use B31.3 on the riser off the subsea wellhead, but several folks suggested that he might want to contiue with API tubulars up to the platform deck).

David

 

[BigInch]

DrillerNic, I think B31.3 has no claim on or against well heads, it simply doesn't mention the subject.

API RP 14E is the only specific coverage I know of that does apply to offshore platforms and MMS and the Coast Guard will see that you follow it.

Zdas is correct in that there will be little difference in materials, as long as the station design factors are used in B31.8, not the pipeline design factors. I think there would be a difference if B31.4 was used, because there you will only find one design factor of 0.72, however both of those codes state that they DO NOT apply to wells, so there's no value to discussing those two codes any further for well site applications ...IMO.

The accepted practice, as far as I've ever seen is, as has already been said above, to use B31.3, or propriatory standards (typically based on the same as a minimum requirement) and include 14E when offshore.

We will design everything from now on using only S.I. units ... except for the pipe diameter. Unk. British engineer

 

[zdas04]

BigInch,
I was pretty sure you were wrong about B31.3 not having language excluding wellsites, so I just read the exclusions section and you are right, I was wrong. B31.3 is apparently broad enough to cover this equipment. I was sure that I had seen exclusionary language in the old versions, but maybe I was smoking something that isn't legal in New Mexico.

So, if onshore wellsite equipment is designed by an engineer then it should be ASME B31.3. If it is "designed" by a high-school dropout production foreman, then Sched 40 PVC connected with ABS glue and 55 gallon drums for knockout pots is still just fine.

David

 

[BigInch]

zdas, In NM as I recall, even the mushroom soup might do that to you. B31.3 has never addressed well pads one way or another that I ever remember and that goes back to my first reading around 1978. Since applicability to well pads is not negated, as the other codes say, we can use it if we want to and the owner agrees. Anything's usually better than nothing.

I have also seen many times exactly what you are talking about when you mentioned the foreman's mash up specials on remote well pads... some not so remote. I personally believe code design of some sort should be required on even remote well pads due to a number of accidents, one fatal, I could only attribute to poor design and operating practices for sand separators, dehys, heaters, field compressors and well meters, relief valves locked closed (because they were always flowing), etc. Many times the pressures are significant and I don't think well pad installation foreman are the ones that should be designing the stuff. I am reasonably certain that BP/ARCO's leak in 2006 on the North Slope gathering system was the result of not being required to pay attention to what was going on in an unregulated system where not even minimal routine inspections were required, leading to excessive corrosion and a very large leak. I'm sure that BP no longer allows unregulated gathering systems to run themselves basically unattended, as they got a pretty significant fine for that one too, if I remember correctly.

But until gathering systems do become regulated, there was some talk about requiring it after the above leak, we have to depend only on the remoteness of these systems for general personnal safety, but unfortunately that still won't prevent environmental damage. The majors and most intermediates all have company standards that cover well pad installations, but most of the smaller independents don't have any standards at all... for anything.

You were right about the number of pretty bad mash ups out there.

We will design everything from now on using only S.I. units ... except for the pipe diameter. Unk. British engineer

 

[JLSeagull]

In instrumentation and control systems my piping facts can be limited. My wellhead activities were associated with a gas storage cavern development project about 15-years ago. Most upstream site work was offshore.

So, I might consider reviewing some of the API codes (on my hard drive) like RP 1111 Design, Construction, Operation, and Maintenance of Offshore Hydrocarbon Pipelines (Limit State Design)
Spec 5L Line Pipe
RP 14E Design and Installation of Offshore Production Platform Piping Systems
RP 5C Welding connections
or even
DNV5 Guidelines No. 14, Free Spanning Pipelines

OK, disregard this message. ;-)

 

[SNORGY]

In Alberta, Canada, the governing Regulatory Authorities (Alberta Boiler Safety Association and the Energy Resources Conservation Board), along with a well-known Producer, have jointly authored a reference tool for the delineation of design scope and Codes at precisely such facilities. It has since been re-published as part of a Directive (ERCB Directive 077). In essence, often the choice of Design and Construction Code is left with the Engineer Of Record / Owner, but at least the choice is limited to two Codes. Often, the selection of the Code to be followed is made as a direct function of whether or not there will be on-site flaring (i.e., no flare, no PSVs, hence P/L Code is selected instead of ASME Code). Materials are selected and cross-referenced in accordance with Tables in the governing P/L Code, so you find a lot of "ASME" materials in "CSA sites", and this practice is endorsed to some extent by various Information Letters published by the ERCB.

In other words, where the Codes don't claim ownership, the Regulators attempt to resolve it, and Regulatory Compliance takes hierarchy over Code Compliance.

As one rather smart engineer once said:

"You can do whatever you want as long as you know what you are doing.".



Regards,

SNORGY.

 

[BigInch]

Good quote.
I might edit it a little bit ...
... as long as you know what we wanted.

JLS, as an instrumentation engineer, you should be able to get away with just the RP 14E, unless you like punishing yourself.

Limit state I leave to DNV code pipelines only. I don't think RP 1111 is widely adopted in practical sense for most work. I'd like to hear from anyone that uses it on a regular basis.

We will design everything from now on using only S.I. units ... except for the pipe diameter. Unk. British engineer