Excessive Pressure Drop in Oil Piping 1

Rosalynn · Apr 3, 2003

I'm troubleshooting an existing operating facility.

We have excessive pressure drop between two parallel oil/water separation vessels and the inlet to the "Sales Oil Cooler" about 200 ft. downstream. The vessels are the third ones in line to receive heavy oil production from the wells in the field.

I've calculated the pressure drop through the control valves (one on the exit of each vessel) and through the piping. The piping is simple: lines off each vessel with gate valves to isolate the control valves, joining at a tee and travelling to the heat exchanger. There are the typical ups, downs, and elbows you'd expect, but nothing complicated. (There are two branch lines, but they are isolated and there is no flow through them.) Yet the pressure drop is 300 kPa instead of 100 kPa (45 psi vs. 15 psi). It is limiting throughput and therefore limiting profits.

I've gone over and over this system. I think my calculations are correct (I've used Fisher Firstvue for the control valves, Hysis and nomographs for the piping effective length and pressure drop). Perhaps I'm too close to see the obvious? I'd welcome your ideas on what to check. Xray the piping for restrictions? Sand in low points? Online cleaning options? There is only one intermediate location for a gauge to be installed--I'll get that done asap and see if it can narrow things down. Since I have two vessels, two flow meters and two control valves in parallel which say the same thing, I'm thinking that they are reading correctly. (The flows are also consistent with other meter readings in the plant.) The gauge at the exchanger is new, and its reading is corroborated by gauges downstream.

Thanks.

samuelliu · Apr 3, 2003

Is there any significant changes on operating temperature? If no, I guess that there must be something blocked the inside of pipe, those might be foreign matters or off-valve/fitting pieces.

Rosalynn · Apr 3, 2003

Reply to samuelliu regarding temperature changes:
No, any change in temperature is negligible (heat loss to surroundings across insulated pipe walls; small J-T change due to pressure drop across control valve).
One of the Firstvue control valve cases I ran said that this is a flashing service, but I figure if it knows that it'll also calculate the pressure drop across the valve for it. In any event, the effect will be minor because the valve pressure drops are relatively low.
Thanks for your input!

DLANDISSR · Apr 3, 2003

Rosalynn:
Do you know what the pressure differential is across the pump is so you know what the pump is actually doing. Compare this with the pump curve to inticate what the fhow should be. Do you know the pressure drop across the valave by acutall measurement? If not your calculation may be faulty or you have the wrong data. Viscosity?? Pipe ID?

Is this a new system or an old system with a new problem?

What is the control basis for the contol valves? Pressure?
Flow? Temperature?

Have you tried opening the control valve 100% slowly and see what effect this has?

If all else fails install presusre taps at various places (before and after the pumps, before and after the control valve, etc.) and measure the pressure drop. You can continue this procedure until you isolate where the pressure drop is occuring.

Rosalynn · Apr 3, 2003

Reply to DLANDISSR:
Sorry, there are no pumps in this piping. The fluid is pressured out through the downstream exchanger and out to tankage.
Good questions/suggestions, though. The control valves are level controllers. At high production rates the valves are 100% open, so yes, we've opened them slowly to 100%. Checking and rechecking calc's, etc., although BORING, must be done. I should do it again.
I've sort of converged on the same "last resort" as you have: more pressure data at intermediate points to isolate the problem. Still wishing for the silver bullet, though.

briand2 · Apr 3, 2003

Rosalynn,

If, as you state, this is (or may be?) a "flashing service", is it possible that you have (for some, or all, of the pipe length), two-phase flow? If so, this would add to the pressure drop, but I wouldn't like to say by how much.

The other point is that I have on several occasions had difficulty when trying to estimate pressure drops in existing pipes. You don't need to change the relative roughness very much to make very significant differences to the pressure drop. I find it difficult enough to predict in practice what the system pressure drop will be for a new installation, hence the need to allow "a bit in hand" for commissioning. How can you be sure that the internal surfaces of the pipe are the same as, or close to, the tabulated roughness values for new, clean pipe?

Finally, with regard to "blockage", if each pipe was reduced in diameter by about 20% compared to as new condition (due to deposits,etc) then this would give a three-fold increase in pressure drop per unit length.

I'm sorry this is not the "silver bullet" you'd like to have, but I don't suppose it exists (I wouldn't mind one for myself!!).

Regards,

Brian

Rosalynn · Apr 3, 2003

Reply to briand2:
Thanks, you raise good points. More doublechecking. My head hurts!

d23 · Apr 3, 2003

Rosalynn:

Has anything changed in the well treating (chemicals) or facility treating/operation? If these are the third vessels in the system I would have doubts about sand unless you are having vessel problems too.

If there is a old fluid analysis from the sales cooler I would get a new one and compare the two.

Not much help, but good luck!

CARF · Apr 4, 2003

Dear Rosalynn,

So you face a much higher pressure drop than you expect from your calculations? Here are some ideas:

1) Calculate again:

http://home.hccnet.nl/m.dijk/pressure_drop_calculator/

2) How do you know the HEX isn't foulded? Measure the pressure difference over it and compare it with the manufactures specifications @ that flow and viscosity.

3) The line is old (rusty, fouled) I would flush it with a temporary pump @ high flow and very high temperature. The fatty coagulations will melt and the high shear forces will get other contaminations out (also in the HEX).

4) If the line is old make and cost you money because the overall production is lowered I would just install a new line with larger inner diameters. So make make a cost benifit analysis.

5) How do you know the correct viscosity of an oil/water fluid?

6) You could decrease viscosity and thus pressure drop by heating the fluid.

7) Increase the setpoint of the level control. Since it's a gravity system every inch in higher level will help to give more static head ! (Pressure = density * 9.81 * dHeight)

Hope this helps,
MVD

Rosalynn · Apr 4, 2003

Reply to d23 and MVD:
Process requirements set the viscosity of the product, so that will not have changed much. Viscosity is measured as one of the product specs too, so we have a good idea of what it is at operating conditions (very little water in this stream--another spec). Can't change the temperature by more than 5 degC either--affects oil/water separation efficiency.
The high-rate, high-temperature circulation idea is interesting. There is a lot of steam in this facility--wonder if a good steaming would be a viable option.
When the plant is limited, the upstream vessel is already high-levelled. Might be able to squeeze a couple of more inches out of there, but not much.

I believe that the sales oil exchanger is fouled, as you suggest. It has a much higher pressure drop than design. But the pressure drop across the piping upstream of it is even worse.

Thanks for the input. When you're troubleshooting, a "no" answer can be as valuable as a "yes", so it is helping.

CARF · Apr 5, 2003

Hi,

Just flush the line with high temperature water (95 degC), perhaps some caustic (NaOH) added as well. Be sure velocities are above 2 m/s. In our food plants (margarine / edible oils) we call this CIP (Cleaning In Place). Special CIP lines are a permanent part of the process line.

Let me know your progress and good luck !

d23 · Apr 5, 2003

Rosalynn

One thing you may want to consider before cleaning with steam or water is to replace a small section of the existing pipe. You will then have a sample piece of pipe for evaluation.

You did not identify a time frame for the problem, but by evaluating the tubing there may be something you can do to extend this MTBF. This may also give you some insight of the sales oil exchanger problem too.

Vienta · Apr 6, 2003

Rosalynn,

I'm no Process Engineer but would the temperature throughout the pipework be having some effect on the viscocity of the oil and thus be creating more friction throughout the system.

Based on the calculated pressure loss, I'm assuming it is not a long line. Heat trace and lagging could be an option.

Hope this simple but maybe obvious suggestion helps.

Good luck anyway.

Rosalynn · Apr 7, 2003

Thanks to MVP, d23, and Vienta for your replies.

If what's laying out is some sort of waxy goo, it's curious that it's not plugging up the line downstream of the cooler as well. But perhaps it's all settled out by the time it leaves the exchanger....
The temperatures in the problem piping section are >100C. The temperatures have changed very little since original commissioning 20 years ago. This is why I wondered about sand instead of waxy material. Could be partially coked junk or something, though. There is no heat tracing or insulation on this piping except where needed for personnel protection.
We've a good clean-in-place company in this region. I may call them to see what they would recommend. They've cleaned some upstream exchangers in the past.

I found two intermediate spots for additional pressure gauges. They're not in the best locations, but perhaps they will localize the problem area further.

There's a company in this region that can do gamma ray scans of piping, vessels, etc. and I know that they can "see" liquid levels, etc. If the gamma ray guys can detect goo, it'll be cheaper than cutting out piping (which would incur production losses). Anybody used this technology? If so, would you recommend it in this case?

TD2K · Apr 7, 2003

I haven't used gamma scanning for this but I would have no doubt it would work. Check the cost, it might be cheaper to try conventional X-rays at first.

Start at your elbows, change of direction, etc. As pointed out, you don't need much of a reduction in area to significantly increase the pressure drop. Alternatively, as your piping is too long, just shoot every 20 feet or so as well as at fittings.

I've had a similar problem on a produced water line where I was running much higher pressure drop than I should have. I'm convinced it was sand but couldn't convince anyone to spring for X-raying as it wasn't a problem (but we weren't that far off the pumps' relief valve setting, then it was going to be a BIG problem ;-)).

mpoffe · Apr 7, 2003

Rosalyn,

I have had the experience of build ups of Aspahltenes and combinations of asphaltenes with scale/sand/silt in vessels and lines. Sometimes the use of xylene will dissolve some or all of the deposits. If your oil stream is more of the paraffinic variety then diesel may work as well.
Regards,
michael

Rosalynn · Apr 8, 2003

Thanks to TD2K and mpoffe for the flushing ideas. I'm going to discuss them with the contract online cleaning guys, and with the site lab guy.

I've rechecked my calculations. There is DEFINITELY a pressure drop problem in the system. So thanks everybody for your input; I'll have that much more confidence when I go and recommend spending money on fixing this.

TD2K · Apr 8, 2003

Rosalyn, if you've checked and rechecked your work, stick to your guns and find out what the problem is.

As a very new engineer years ago, I was given the task of figuring out what our debutanizer didn't seem to be working.

Okay, it took me ages (the experienced engineers had all been pulled off this plant to work on the new sister plant design/startup and all the first plant had were new grads) but I finally concluded the frigging tower had to be flooding. 'Nope, no way, can't be' I was told. They finally opened it during the turnaround after I kept pushing for it and found the lower 1/2 absolutely full of polymerized butadiene. Found out later, this is pretty common in this type of tower. AND, our sister technical resource in the US, when asked prior to the T/A, had said there couldn't be a problem with the column. Turns out they had in this design lowered the tower pressure to lower the temperature to correct this very problem and were so sure that it was successful that they didn't even tell us this was a known problem. Ha.

Rosalynn · Apr 9, 2003

TD2K: Thanks for the encouragement, and for the story. Work in real plants doesn't match the text books all the time, does it. That's when things get fun. The fact that there's a pile of money at stake either way (whether you're right or whether you're wrong) adds to the excitement. The "experts" were wrong about a lab problem during my masters degree work, so I identify with your tale. I lost 3 months following their advice before a buddy and I solved it, sort of by trial and error. The only person who can solve the problem sometimes is the one who "owns" it.

I talked to an inspection friend of mine. He had a great suggestion--thermography on the uninsulated section of piping. Crap on the inside of the line will act as an insulator, and a good thermographer will be able to identify the temperature differences--and generate a pretty picture of his findings. Relatively cheap, too. I'm going for it. (Doesn't say how to get the stuff out of there once it's proven to be present, but hey, one step at a time.)

Rosalynn · Jun 12, 2003

I don't know how many people will read this, but the mystery is solved, and there are one or two lessons in it.

When we take instrumentation and control courses in school or get sent on courses for work, the focus on pressure drops tends to be on the pressure drop through control valves. The pressure drop through flow elements themselves is mentioned in passing--maybe.

There are two orifice plates in the system I've been troubleshooting. Their combined pressure drop at maximum flow is 60 psi. The allowable pressure drop for the whole system is only about 75 psi. Pretty obvious now where the problem is, isn't it! I'd assumed that the orifice plate pressure drops were similar to those for their associated control valves--quite low. NOT.

These plates aren't original. They were changed out to smaller ones in an effort to get more accurate flow measurement during a period when the plant was at low production. So the paper trail was a bit harder to decipher.

Thermal scanning wasn't a waste, as we did find significant build-up at one elbow. But it still couldn't explain the whole story, so I had to search further. Now the instrumentation guy and I are looking at each other a bit sheepishly. We could have identified the restriction a lot faster if Engineering and Instrumentation had had better communication in the first place, or if change management was done better/more thoroughly.

Live and learn, eh.

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