Tubing Back-Pressure

[NickJZ]

Hello everyone!

I've been working on a project to evaluate the effects of tubing back pressure to deal with gas interference in sucker-rod-pumped wells.
Before the Back Pressure Regulator (BPR) was installed, the well was pumping around 28 BOPD and 41.3 MSCF (1475 GOR) with a 57% volumetric efficiency, after the valve was installed (set at 200 psi but tubing pressure increased up to 400 psi and has been oscillating between 350-400) oil production increased to 40 BOPD but gas production dropped to 10.3 MSCF (258 GOR) and volumetric efficiency ranges from 55 to 64%. Since the back pressure is merely keeping gas bubbles in solution I was expecting at the very least for gas production to be constant and for volumetric efficiency to increase. But volumetric efficiency remained sort of constant whilst the gas production decreased. Although the oil production did indeed increase, can anybody explain what is going on?

Thanks in advance.

 

[zdas04]

I've done a lot of experimentation on this and the benefits of backpressure increase with decreasing pressure. A pump pumping against 40 psig flowing tubing pressure (FTP) will nearly always significantly improve its volumetric efficiency by increasing the backpressure to over 145 psig. A pump facing 200 psig FTP will not result in a significant increase in pump performance. I published an Oil & Gas Journal article a few years ago that addresses many of these issues.

Work I've done since show results like

You can see from this chart that the impact on the hydrostatic pressure is very much a function of the imposed pressure at the top. You don't say what the starting FTP was, but it likely was high enough that the physical volume that the gas occupies in the tubing was low enough not to be a significant factor.

If you look at the pressure gradient down the tubing (image below), you can see that my "high pressure" version only has 320 psig on it and the line without added backpressure is nearly straight and just slightly lower than the no-gas line. There just isn't enough of a problem at FTP above about 150 psig to make it worth bothering.

[bold]David Simpson, PE[/bold]
MuleShoe Engineering

In questions of science, the authority of a thousand is not worth the humble reasoning of a single individual. Galileo Galilei, Italian Physicist

 

[NickJZ]

Hello zdas04.

Thanks for your response. I am still not sure if I fully understand your point.
The starting FTP was 160 psig. The service company we're working with advised us to set backpressure at 200 psi and to increase it over time until we reached max 400-450 psi (pump's limit is around 500-600 psi). So far we've tested two wells.

The first one being the one I just described.

The second one, on the other hand, although we set the backpressure regulator at 200 psi as well, the oil production didn't increase and volumetric efficiency remained about the same. We're hoping that if we increase tubing back pressure, we'll have a change soon.

But then again, I am still not sure what is really going on downhole. It all seems counter-intuitive to me and feels like I'm missing something or the data I've gotten so far just isn't representative enough.

Thanks.

 

[zdas04]

NickJZ,
Think of physical volumes. At higher pressure, the same mass flow rate (or volume flow rate at standard conditions) of gas takes less physical volume than it does at lower pressures. This is far from a linear function.

Converting volume flow rate of a gas at standard conditions (which is constant for a given stream) to actual volume flow rate (which isn't constant at all) requires dividing standard pressure by actual pressure. If flowing tubing pressure is 0 psig (call it sea level, so 14.7 psia), then if temperature is the same as standard temperature, the multiplier is 1.0. If FTP is raised to 50 psig (64.7 psia), then the multiplier goes down to 0.22 (and the same mass of gas takes up 22% of the physical volume that it took at zero psig). By the time you reach 145 psia the multiplier drops to 0.1. Increasing the backpressure farther has a diminishing effect (200 psig would be 6.8% and 400 psig would be 3%, an impact, but not enough to change the performance of the pump).

Raising FTP from 160 psig to 200 psig would have approximately zero impact on anything.

[bold]David Simpson, PE[/bold]
MuleShoe Engineering

In questions of science, the authority of a thousand is not worth the humble reasoning of a single individual. Galileo Galilei, Italian Physicist

 

[NickJZ]

zdas04,

I think I understand what you mean now. In terms of physical volumes and looking at the graph you posted, it makes more sense now.
However, wouldn't this be even more strange now? Starting FTP was 160 psig and although it was set to 200 psig, it went up to 400 psig, which according to you would have a 3% of an impact (not that much), and yet, the gas production went down dramatically (from 41.3 to 10.3).

Your explanation would help me understand why the volumetric efficiency didn't significantly improve (pump depth is at around 5000 ft), but the actual volume flow rate I'm getting (both 41.3 and 10.3) are at standard conditions.

 

[zdas04]

First off, none of what I've been talking about has anything to do with gas production up the annulus. That bit of fluid mechanics does not see your pump or your backpressure valve. I put backpressure valves on all positive displacement pumps to try to get the fluid within the pump and (slightly less importantly) in the tubing to be as close to acting like a continuous phase liquid as I possibly can. I know I cannot keep the gas out of the pump, so I want to minimize the physical volume that it occupies.

Second, while forcing the gas in the pump into a smaller volume significantly improves pump efficiency and often increases liquid flow (in the chart I posted above we had to slow the PCP from over 300 rpm to 80 rpm to keep from over pumping the well) it rarely makes a significant change in flowing bottom hole pressure. Without changing bottom-hole pressure what would be the mechanism for increasing gas production? You need to look elsewhere for the source of the gas flow reduction.

I'd love to spend some time with your wells and your data to try to help resolve this, but that is more effort than I can put in for free. My accountant hates that I spend any time at eng-tips.com giving away advice that my clients pay good money for. Good luck with this.

[bold]David Simpson, PE[/bold]
MuleShoe Engineering

In questions of science, the authority of a thousand is not worth the humble reasoning of a single individual. Galileo Galilei, Italian Physicist

 

[sraesttam]

Nick, I cannot explain what is going on. One would think that since you are producing more oil (and presumably total fluid), you are drawing the reservoir down further and would also have an increase in gas production. (Unless the casing pressure increased...) Do you have any casing gas gathering lines that are causing the gas tests to not match the real produced volumes? I have seen horizontal wells slug liquid up the annulus and get sent down backside gas gathering lines. These liquids are knocked out and allocated back to the wells, but were not apart of the tested volumes.

This seems hard to diagnose since there are just so many potential factors. Are these wells on POCs? How have your percent run times changed and the number of cycles per day? Did your POC calculated pump intake pressure change? Did your fluid level shots change? Is this a vertical well or a horizontal well that slugs?

The reason I commented is this: As you increase your tubing back pressure, it changes other parameters in your rod string loading. I have found that as you increase tubing back pressure, the bottom minimum stress usually decreases. You can end up running your bottom rod taper in compression if there are not enough sinker bars installed. I have found a lot of rod installations designed for 50 PSI tubing pressure where the bottom rod taper is running in compression due to having 400 PSI on the tubing.

Sorry - I don't think I have much to add here except the warning about rod compression.

 

[LittleInch]

The bit I don't get is this "set at 200 psi but tubing pressure increased up to 400 psi and has been oscillating between 350-400"

If you set a back pressure controller to 200 psig, how are you getting 350-400?? This implies the back pressure controller isn't working or is undersized and is wide open but choking the well? What is the pressure downstream? Do you have a choke valve?

Without knowing what your bubble point and bottom hole pressures are you won't be able to figure out what is happening at the bottom of your tubing / reservoir conditions or how that impacts on oil or gas production.

Do you have annulus flow as well? How is the well set-up? How are you testing the flows, GOR and standard volumes.

Change one thing and it all can change so sorting out cause and effect might not be straightforward.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[NickJZ]

@sraesttam & @LittleInch thank you for your responses, I apologise in advance for English isn't my native language.

To answer some of your questions:
No, the wells do not have POC. The fluid level shots haven't changed, at least not dramatically.
They are slanted wells that slug.

As for the pressure increasing up to 400 psi, I've asked around and turns out the person who did it didn't do it correctly. We do have a choke valve.

Annulus is connected to flow line. They're testing the flows once they reach the test separator through an orifice plate. GOR from an estimate of produced gas in barton charts.

Thank you.

 

[sraesttam]

Nick, was the fluid level shot on the left taken earlier than the one on the right? According to the fluid level shot, the casing pressure increased from 95 PSI to 195 PSI between these two shots. Producing BHP also increased from 677 PSI to 740 PSI. Did your flow line pressure increase or did the casing get choked back?