Folks, in our operations we produce natural gas from numerous wells. A question has arisen in regards to what standard should we should be using to design piping once the gas leaves the wellhead "tree"?? Often at these sites, we have piping that enters chokes, valves, thermal loops, and separators. At some of these sites, we may have a compressor that boosts pressure to enter a gathering system. A scope diagram in ASME B31.8 (Fig Q2 in my 1999 edition) states that B31.8 "starts at outlet of separation and/or processing plant". What standard is used for the section between well and separator, or well and other wellsite equipment??? Your feedback is appreciated.
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Which standard applies for wellsites: B31.8 or B31.3? 1
- Thread starter RRE
- Start date
Check Scope diagram Q1
B31.3 is for the PROCESS PLANT
B31.8 is for the TRANSMISSION PIPELINE
Use B31.3 between XMAS tree flowline outlet (Wing valve) and the export transmission PIPELINE inlet, typically at Pig launcher inlet.
Use B31.8 for export transmission PIPELINE, i.e. at pig launcher outlet.
The pipeline ESDV located at the pig launcher separates the two codes. Remember though that ID of ESDV and pig launcher at neck must match PIPELINE ID.
Hope this helps
Regards
Mogens
B31.3 is for the PROCESS PLANT
B31.8 is for the TRANSMISSION PIPELINE
Use B31.3 between XMAS tree flowline outlet (Wing valve) and the export transmission PIPELINE inlet, typically at Pig launcher inlet.
Use B31.8 for export transmission PIPELINE, i.e. at pig launcher outlet.
The pipeline ESDV located at the pig launcher separates the two codes. Remember though that ID of ESDV and pig launcher at neck must match PIPELINE ID.
Hope this helps
Regards
Mogens
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1
- #3
RRE,
I've spent many unproductive hours in this discussion, and the above from Mogens is the first time I've ever heard anyone make that argument that the wellsite is B31.3. The B31.3 requirements even make some sort of sense offshore (where the well's production facilities look more like a plant than anything else), but none onshore.
My research has indicated quite clearly that no one (not even DOT) claims jurisdiction over wellsite piping from the master valve through the production separator. I've been building wellsite piping to B31.8 for several years, but the arbitrary and (I think) capricious point where jurisdiction begins has caused me a lot of heart burn. In most onshore gas fields, the producer owns the piping upto (but usually not including) the meter run. Most times the Gatherer owns the meter run. If we follow the letter of B31.8, then the piping between the outlet of the separator and the meter run are B31.8 (and in jurisdictional piping fall under DOT 192) - this would often include the wellsite compressor which makes wellsite compression a B31.8 compression station (including the requirements for fencing, ESD system, no threaded fittings, and fire suppression on compressor skids you can haul around in the bed of a pickup). We've tried to challenge this with our B31.8 committee member and he doesn't return calls. This is a very tough issue and each company will have to deal with it theirselves.
David
I've spent many unproductive hours in this discussion, and the above from Mogens is the first time I've ever heard anyone make that argument that the wellsite is B31.3. The B31.3 requirements even make some sort of sense offshore (where the well's production facilities look more like a plant than anything else), but none onshore.
My research has indicated quite clearly that no one (not even DOT) claims jurisdiction over wellsite piping from the master valve through the production separator. I've been building wellsite piping to B31.8 for several years, but the arbitrary and (I think) capricious point where jurisdiction begins has caused me a lot of heart burn. In most onshore gas fields, the producer owns the piping upto (but usually not including) the meter run. Most times the Gatherer owns the meter run. If we follow the letter of B31.8, then the piping between the outlet of the separator and the meter run are B31.8 (and in jurisdictional piping fall under DOT 192) - this would often include the wellsite compressor which makes wellsite compression a B31.8 compression station (including the requirements for fencing, ESD system, no threaded fittings, and fire suppression on compressor skids you can haul around in the bed of a pickup). We've tried to challenge this with our B31.8 committee member and he doesn't return calls. This is a very tough issue and each company will have to deal with it theirselves.
David
Just to add a north-of-the-border flavour to this discussion, I've actually gone through the same question on natural gas wells here in Alberta. Canada doesn't use B31.8, we refer to CSA Z662 for pipelining, though we do use B31.3 for process piping. On the wells I've done, typically I'll see a 3000# or 5000# flange mated to the master or wing valve on the wellhead, and everything between that flange and the sales riser (on a single-well site) is to B31.3. The transition to CSA piping usually occurs at the sales isolation valve, though that's a bit of a grey area and we can basically make the transition anywhere downstream of the last piece of wellsite production equipment.
Mogens,
I don't know about "out of line", your comment just suprised the heck out of me. I appreciate your clarification that you do B31.3 offshore, that makes sense.
Scipio,
Is the choice of B31.3 on the wellsites due to cold-weather considerations (as I recall the arctic circle is real close to Waterton National Park)? I've talked to the BP guys around Edmonton and they have the same questions about codes that we have in sunny New Mexico - I've seen a whole bunch of 5,000 psi flanges with threaded companion flanges and line pipe from that point on.
David
I don't know about "out of line", your comment just suprised the heck out of me. I appreciate your clarification that you do B31.3 offshore, that makes sense.
Scipio,
Is the choice of B31.3 on the wellsites due to cold-weather considerations (as I recall the arctic circle is real close to Waterton National Park)? I've talked to the BP guys around Edmonton and they have the same questions about codes that we have in sunny New Mexico - I've seen a whole bunch of 5,000 psi flanges with threaded companion flanges and line pipe from that point on.
David
Zdas04 is correct.
The B31 Codes now say that it is up to the owner to select the most applicable code. Having said that, the following is what I understand to be the general intent.
Production lines such as wellhead piping and flowlines are not covered by any ASME B31 code. Some owners elect to use, for example, B31.4 or B31.8 for flow lines, but they are using them to establish an applicable standard. I have seen, for example, discussions on whether to use B31.4 or B31.8 for flow lines with high H2S vapor content.
The piping in the separations plant is considered to be process piping, so B31.3. Piping after a separator, including a wellhead seperator, is B31.8. Compressor stations, meter stations, transportation piping, etc is claimed by B31.8.
On an offshore gas production platform, most, I believe, are designed to B31.3, but B31.8 also can be used. There are a number of changes being incorporated into ASME B31.8 that will make it more applicable to such piping.
The specific answer to your question as to what to do with the piping between the well head and the separator, is that there is no standard which claims it. It is up to you to use what you think is most applicable.
The B31 Codes now say that it is up to the owner to select the most applicable code. Having said that, the following is what I understand to be the general intent.
Production lines such as wellhead piping and flowlines are not covered by any ASME B31 code. Some owners elect to use, for example, B31.4 or B31.8 for flow lines, but they are using them to establish an applicable standard. I have seen, for example, discussions on whether to use B31.4 or B31.8 for flow lines with high H2S vapor content.
The piping in the separations plant is considered to be process piping, so B31.3. Piping after a separator, including a wellhead seperator, is B31.8. Compressor stations, meter stations, transportation piping, etc is claimed by B31.8.
On an offshore gas production platform, most, I believe, are designed to B31.3, but B31.8 also can be used. There are a number of changes being incorporated into ASME B31.8 that will make it more applicable to such piping.
The specific answer to your question as to what to do with the piping between the well head and the separator, is that there is no standard which claims it. It is up to you to use what you think is most applicable.
zdas04,
Actually the choice of B31.3 is pretty much the reasoning that cb4 laid out. It just gives us a standard to work with once you get downstream of the API wellhead. Canadian pressure piping code permits the use of B31.3, B31.3, B31.4, B31.5 and B31.9. Natural gas pipelining (we do use B31.4 for oil, though) is done to CSA Z662, which has a figure comparible to Q1 & Q2 in B31.8 outlining it's scope in offshore and onshore facilities. For onshore facilities, our scope specifically excludes "onshore gas well, including any wellsite production facilities", which in that case includes wellsite boosting pumps and compressors.
Now, since Z662 excludes gas wells & associated facilities on the same lease, we're pretty much left with B31.3. We could use Z662 if we wanted, but it can be more rigorous and materials more expensive than B31.3 design & construction - for instance, A-333 Grade 6 isn't accepted as low temperature pipe under Z662 unless it's dual-certified.
As for cold weather considerations, it might be a consideration, but we even use B31.3 for insulated and traced lines, though everything exposed to ambient conditions has to be designed for low temp applications (we usually get a few days a year between January and March where it hits -40°C), but you're a little off on your proximity recollections, zdas04, arctic circle is about 2000 km's north of Waterton
If we were much closer, trust me, I'd be working south of the border!
Actually the choice of B31.3 is pretty much the reasoning that cb4 laid out. It just gives us a standard to work with once you get downstream of the API wellhead. Canadian pressure piping code permits the use of B31.3, B31.3, B31.4, B31.5 and B31.9. Natural gas pipelining (we do use B31.4 for oil, though) is done to CSA Z662, which has a figure comparible to Q1 & Q2 in B31.8 outlining it's scope in offshore and onshore facilities. For onshore facilities, our scope specifically excludes "onshore gas well, including any wellsite production facilities", which in that case includes wellsite boosting pumps and compressors.
Now, since Z662 excludes gas wells & associated facilities on the same lease, we're pretty much left with B31.3. We could use Z662 if we wanted, but it can be more rigorous and materials more expensive than B31.3 design & construction - for instance, A-333 Grade 6 isn't accepted as low temperature pipe under Z662 unless it's dual-certified.
As for cold weather considerations, it might be a consideration, but we even use B31.3 for insulated and traced lines, though everything exposed to ambient conditions has to be designed for low temp applications (we usually get a few days a year between January and March where it hits -40°C), but you're a little off on your proximity recollections, zdas04, arctic circle is about 2000 km's north of Waterton
If we were much closer, trust me, I'd be working south of the border!Sorry Scipio, geography never was my strong suit. If I'm reading your response correctly, the "no threaded process pipe" proscription in B31.3 is OK with your field guys? Our guys in the desert would have kittens if I suggested that we couldn't thread 2 and 3-inch flow lines on location.
David
David
zdas04,
No worries on location, I'm used to it As for "no threaded process pipe", I'm not sure where you see that in B31.3, as I read paragraph 314 there's no problem with it, unless you consider natural gas Category "M" fluid service - we don't unless it's acid gas. As a matter of engineering practice, though, generally everything in the oilpatch here (that I've seen, anyway) is built buttwelded & flanged at 2" and up. You'll see some exceptions, 2" drain headers to atmospheric storage tanks, for instance, are frequently just NPT. The place I sometimes butt heads with other field guys (I'm one myself) is smaller than 2". The only place you can usually expect to see NPT out here is on lines 1.5" and smaller in sweet service.
No worries on location, I'm used to it
As for "no threaded process pipe", I'm not sure where you see that in B31.3, as I read paragraph 314 there's no problem with it, unless you consider natural gas Category "M" fluid service - we don't unless it's acid gas. As a matter of engineering practice, though, generally everything in the oilpatch here (that I've seen, anyway) is built buttwelded & flanged at 2" and up. You'll see some exceptions, 2" drain headers to atmospheric storage tanks, for instance, are frequently just NPT. The place I sometimes butt heads with other field guys (I'm one myself) is smaller than 2". The only place you can usually expect to see NPT out here is on lines 1.5" and smaller in sweet service. Since I don't use B31.3, I can't quote references (and since I retired last week I no longer have access to BP's online references). The B31.8 Compressor Station language in 843.511 ("All compressor station gas piping, other than instrument, control, and sample piping, to and including connections to the main pipeline shall be of steel and shall use a design factor, F, per Table 841.114B" and the 50% design factor in table 841.114B is taken by BP's Engineering Police as saying everything in a compressor station must be welded. Maybe that is going way overboard as I look at it from the consulting world beyond BP.
David Simpson, PE
MuleShoe Engineering
and the 50% design factor in table 841.114B is taken by BP's Engineering Police as saying everything in a compressor station must be welded. Maybe that is going way overboard as I look at it from the consulting world beyond BP.David Simpson, PE
MuleShoe Engineering
The choice to use ASME B31.3 is certainly a legitimate option. Threaded piping can be used in process piping applications (even Category M with certain limitations with respect to joint design). I would find it unusual to have B31.3 specified for the well head application, but it, as well as all of the B31 Codes, provide a safe installation. Perhaps the rationale for its selection in your case was that it was considered more likely to have people working around the piping installation. Bottom line, per my prior response, it is the owner's choice.
zdas04,
Sounds about right, since I've never seen B31.8 it would stand to reason it didn't sound familiar! I understand where you're coming from with regards to BP's "Engineering Police", I still see BP title blocks on some of the specs I deal with
cb4,
Actually the rationale in my case (which, as far as I know is nation-wide, not just current & past clients) is that Canada doesn't recognize B31.8, using CSA Z662 instead. Since Z662 explicitly excludes wellsite facilities from it's scope, B31.3 is about the only relevant code left. At least for gas wells, B31.4 is recognized up here, so oil wells might be a different story.
Sounds about right, since I've never seen B31.8 it would stand to reason it didn't sound familiar! I understand where you're coming from with regards to BP's "Engineering Police", I still see BP title blocks on some of the specs I deal with
cb4,
Actually the rationale in my case (which, as far as I know is nation-wide, not just current & past clients) is that Canada doesn't recognize B31.8, using CSA Z662 instead. Since Z662 explicitly excludes wellsite facilities from it's scope, B31.3 is about the only relevant code left. At least for gas wells, B31.4 is recognized up here, so oil wells might be a different story.
TMOC
Mechanical
- May 26, 2003
- 4
I think there is one code being missed here. Realistically API RP 14E should be used. Although this is an offshore spec, it is used (at least in Australia) for onshore oil & gas production wells - mostly because it has allowances for erosion and corrosion by sand, CO2, H2S, etc.
Having sais that, the systems I have been involved with use B31.3 (or AS4041) from immediately downstream of the Hi-Lo to the break flanges on the removable spool - downstream of the orifice meter. Break flanges / removal spool is installed to make way for the work-over rig.
The pipeline code is used from the break flanges through to the flowline.
Hope this helps.
Having sais that, the systems I have been involved with use B31.3 (or AS4041) from immediately downstream of the Hi-Lo to the break flanges on the removable spool - downstream of the orifice meter. Break flanges / removal spool is installed to make way for the work-over rig.
The pipeline code is used from the break flanges through to the flowline.
Hope this helps.
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