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Max Flow Rate 1
- Thread starter newengr
- Start date
Max mass flow rate in the pipe occurs at choked flow conditions (M=1) and occurs at upstream-to-downstream pressure ratio of approximately 0.545.
Velocity = volumetric flowrate / cross-sectional area. Volumetric rate varies down the length of the pipe because the density changes down the pipe length. However, for back of the envelope calcs you can assume the density is constant. Thanks!
Pete
Velocity = volumetric flowrate / cross-sectional area. Volumetric rate varies down the length of the pipe because the density changes down the pipe length. However, for back of the envelope calcs you can assume the density is constant. Thanks!
Pete
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1
- #3
Newengr - Consider picking up a copy of "Flow Of Fluids Technical Paper No. 410" by Crane. It's a thin, soft cover publication that will pretty much cover anything you'll ever need to know about fluid flow through pipes, valves & fittings.
GasDistEng
Mechanical
I would recommend using the general flow equation with the Colebrook friction factor for your flow equation/ pressure drop calc. Make sure to get all of your equivalent lengths for your fittings, valves, etc. For fuel gas (Natural or Propane) you should try to keep your velocities below 100 ft. per second as a general rule. This will help to keep the noise down - especially in high flow conditions. If this a low flow application 1 MMBTU to 3 MMBTU (at 7" W.C. to 5 PSIG) you can size with tables out of NFPA 54. Let me know if you need equations and/or examples.
- Thread starter
- #5
I was using the equation Q = V * A.........where V was assumed to be max velocity of natural gas (100 ft/s) and Diameter of pipe was 12"...I calculated a Q of 6.79ft3/day, but I know there is at least 41MMSCFD going through that pipe....What did I do wrong?
Newengr might just be talking about selecting a pipe based on a maximum "practical" velocity (i.e. one which doesn't involve too much deltaP). GasDistEngr finds 100 fps to be useful. I'd personally start in the 350 fps range for the sake of capital economy and but still stay well away from choked flow. I think you can handle the noisy components individually rather than by spending money on oversized pipe.
Under any circumstances, the maximum velocity in the pipe is effectively sonic (as indicate above as choked flow)
Mach1 = sqrt( g * gamma * R * T / M)
g = gravitational constant 32.174 fps_s
gamma = ratio of specific heats Cp/Cv
R = Universal constant = 1545.5 ft.lb/lbmol_degR
T = temp degR
M = Mol wt
Because the velocity is density dependent, the actual pressure influences the true mass flow and there is no "maximum" flow, just a maximum velocity.
A codicil about the choked flow deltaP. The upstream to downstream pressure ratio given by 74Elsinore applies to an orifice rather than a pipe and is based on generating sonic flow in the orifice throat. The pipe itself is limited when flow is at its least dense, which is at the downstream end. The ratio depends very much on the gas properties and relationship between the pipe and where the flow goes next. Rather than explain this imperfectly, I suggest looking at "Perry", section 5 which has very good explanation.
Under any circumstances, the maximum velocity in the pipe is effectively sonic (as indicate above as choked flow)
Mach1 = sqrt( g * gamma * R * T / M)
g = gravitational constant 32.174 fps_s
gamma = ratio of specific heats Cp/Cv
R = Universal constant = 1545.5 ft.lb/lbmol_degR
T = temp degR
M = Mol wt
Because the velocity is density dependent, the actual pressure influences the true mass flow and there is no "maximum" flow, just a maximum velocity.
A codicil about the choked flow deltaP. The upstream to downstream pressure ratio given by 74Elsinore applies to an orifice rather than a pipe and is based on generating sonic flow in the orifice throat. The pipe itself is limited when flow is at its least dense, which is at the downstream end. The ratio depends very much on the gas properties and relationship between the pipe and where the flow goes next. Rather than explain this imperfectly, I suggest looking at "Perry", section 5 which has very good explanation.
See, this is what happens when you get in a hurry and try to answer these posts between dealdines... ;-)
The 0.545 ratio applies to steam across an orifice plate. I did not calculate it for fuel gas across a long pipe. The ratio for any system depends on the gas properties. Thanks for correcting me. Been working two-phase steam systems too long... Thanks!
Pete
The 0.545 ratio applies to steam across an orifice plate. I did not calculate it for fuel gas across a long pipe. The ratio for any system depends on the gas properties. Thanks for correcting me. Been working two-phase steam systems too long... Thanks!
Pete
Going back to NewEngnr's 6/17 post. The difference between Q=VA coming up with 6.7 MMCF/d and over 41 MMCF/d is the adjustment from ACF to SCF. If your line is running at 100 psig at 6,000 ft elevation, then the "simple" equation becomes:
Q=(Pi/4)*(d/12)^2 * v *(86400 sec/day) * (100+11.6)/14.7
that's assuming constant temp and constant compressibility, neither is valid but both are good enough. For 12" pipe and 100 ft/sec the above gives you 53 MMCF/d.
I also use 100 ft/sec as a design max velocity. I find that keeping slugs slow reduces the supports required for transient stresses. Significantly higher velocities saves piping and valving costs, but increases support requirements and errosion risks--if it's not a wash its close enough for me.
Q=(Pi/4)*(d/12)^2 * v *(86400 sec/day) * (100+11.6)/14.7
that's assuming constant temp and constant compressibility, neither is valid but both are good enough. For 12" pipe and 100 ft/sec the above gives you 53 MMCF/d.
I also use 100 ft/sec as a design max velocity. I find that keeping slugs slow reduces the supports required for transient stresses. Significantly higher velocities saves piping and valving costs, but increases support requirements and errosion risks--if it's not a wash its close enough for me.
That's fine if you're expecting liquid slugs. In a totally dry gas system though you can use higher velocities as a design guideline. Economic tradeoff.
In point of fact there is an upper limit ("maximum flow"
of mass flow. Velocity will increase as discussed past M=1 (accompanied by the formation of a shock) but there is a point, in a closed conduit, beyond which any further lowering of the downstream pressure will not change the flowrate. Reference any gas dynamics textbook for a discussion. Thanks!
Pete
In point of fact there is an upper limit ("maximum flow"
of mass flow. Velocity will increase as discussed past M=1 (accompanied by the formation of a shock) but there is a point, in a closed conduit, beyond which any further lowering of the downstream pressure will not change the flowrate. Reference any gas dynamics textbook for a discussion. Thanks!Pete
That's fine if you're expecting liquid slugs. In a totally dry gas system though you can use higher velocities as a design guideline. Economic tradeoff.
In point of fact there is an upper limit ("maximum flow" of mass flow. Velocity may increase as discussed above beyond M=1 (accompanied by the formation of one or more shock waves) but there is a point, in a closed conduit, beyond which any further lowering of the downstream pressure will not change the flowrate. Reference any gas dynamics textbook for a discussion. Maybe I misunderstood your point? ;-) Thanks!
Pete
In point of fact there is an upper limit ("maximum flow"
of mass flow. Velocity may increase as discussed above beyond M=1 (accompanied by the formation of one or more shock waves) but there is a point, in a closed conduit, beyond which any further lowering of the downstream pressure will not change the flowrate. Reference any gas dynamics textbook for a discussion. Maybe I misunderstood your point? ;-) Thanks!Pete
I guess I'm a bit cynical about ever finding a "totaly Dry Gas system". Our main line spec in the 4-corners is 7 lbm/MMCF--for a 4 BCF/day system that's 3,300 gal/day into the pipe. Can it collect in a low place outside of Bakersfield and hit the city gate with a high-velocity slug? You bet it can. Mr. Murphy has something to say about whatever can go wrong will go wrong in the worst possible way.
All this says nothing about the Hp required to replenish the pressure lost due to friction. At 100 ft/sec in a 12-inch line you'll lose 17 psi/mile. At 350 ft/sec you're moving (at 100 psig downstream) 180 MMCF/d, but at the cost of 180 psi/mile drop. That equates to 10,000 Hp to recover a mile's worth of dP.
Any discussion of sonic flow within a pipe is purely academic. Sonic flow is very dense and quite errosive. Any pipeline designed for sonic flow (if you could even do it, I'm not so sure you could) would have to deal with economic issues that boggle the mind.
All this says nothing about the Hp required to replenish the pressure lost due to friction. At 100 ft/sec in a 12-inch line you'll lose 17 psi/mile. At 350 ft/sec you're moving (at 100 psig downstream) 180 MMCF/d, but at the cost of 180 psi/mile drop. That equates to 10,000 Hp to recover a mile's worth of dP.
Any discussion of sonic flow within a pipe is purely academic. Sonic flow is very dense and quite errosive. Any pipeline designed for sonic flow (if you could even do it, I'm not so sure you could) would have to deal with economic issues that boggle the mind.
I guess I was referring to his initial question about fuel gas. In my experience with the fuel gas systems around here they are usually (now THERE'S the watchword) bone-dry. I don't remember the PG&E/SOCAL spec for lbm moisture/MMBtu around here. And, my experience is limited to pipeline spurs and on-lease/in-plant distribution systems of, at most, 20 miles in length.
While we always install scrubbers just downstream of the onsite PRV stations and the burners on various fired equipment I have yet to see one of them dump any liquids. Not saying they won't, though, and I don't live in front of a gas scrubber, so... Your points are well-taken. Just be sure you can justify the expense on beefed-up supports and scrubbers.
As I said, this is a trade-off and the selection of flow rate thru a known pipe is not a trivial question and is certainly more complex than a V=Q/A analysis.
Don't you just love the real world? As one of my profs used to say - Life is a hard teacher - it makes you take the exam BEFORE you've had a chance to study . . .
zdas, where are you at? I did quite a few projects at the MCU when I was with Mobil. I always loved going there and always made it a point to stay over an extra day to drive around and check out the sights. Beautiful country around there. I would move to Cortez in a second if my wife would go there. Thanks!
Pete
While we always install scrubbers just downstream of the onsite PRV stations and the burners on various fired equipment I have yet to see one of them dump any liquids. Not saying they won't, though, and I don't live in front of a gas scrubber, so... Your points are well-taken. Just be sure you can justify the expense on beefed-up supports and scrubbers.
As I said, this is a trade-off and the selection of flow rate thru a known pipe is not a trivial question and is certainly more complex than a V=Q/A analysis.
Don't you just love the real world? As one of my profs used to say - Life is a hard teacher - it makes you take the exam BEFORE you've had a chance to study . . .
zdas, where are you at? I did quite a few projects at the MCU when I was with Mobil. I always loved going there and always made it a point to stay over an extra day to drive around and check out the sights. Beautiful country around there. I would move to Cortez in a second if my wife would go there. Thanks!
Pete
I'm in Farmington, NM and work a CoalBed Methane field (welsite facilities and company-owned gathering system) in northwest NM and southeast CO.
I like the real world a lot better than academic stuff. I'm studying to take my PE in the fall and those contrived problems feel awfully unreal.
I missed the point about the question concerning fuel. I just focused on the 12-inch pipe and saw transmission. On wellsite fuel (typically 1" or 2" pipe) I see a lot of water that becomes real solid in the winter. Things get real ugly when you're pumping blood, guts, and feathers.
David
I like the real world a lot better than academic stuff. I'm studying to take my PE in the fall and those contrived problems feel awfully unreal.
I missed the point about the question concerning fuel. I just focused on the 12-inch pipe and saw transmission. On wellsite fuel (typically 1" or 2" pipe) I see a lot of water that becomes real solid in the winter. Things get real ugly when you're pumping blood, guts, and feathers.
David
Yeah I hear you on raw gas field gathering systems. That gas is totally saturated so the design condiotions are much different. Lots of field scrubbers and knockout pots.
There was a little café in McElmo Creek or Aneth, or maybe it was Montezuma Creek, I forget which, that we used to eat at all the time when I was doing work at the McElmo Creek Unit. They made awesome frybread tacos. I can't remember the name of it. You know which one? You ever get to the Hovenweep monument? Well now I'm waaaaay off topic... Thanks!
Pete
There was a little café in McElmo Creek or Aneth, or maybe it was Montezuma Creek, I forget which, that we used to eat at all the time when I was doing work at the McElmo Creek Unit. They made awesome frybread tacos. I can't remember the name of it. You know which one? You ever get to the Hovenweep monument? Well now I'm waaaaay off topic... Thanks!
Pete
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