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Function of Tubing Back Pressure on Rod Pumping Wells

I encounter a lot of different beliefs in the oilfield from different operators and pumpers as to what the purpose is for holding tubing back pressure on rod pumping wells and how much back pressure to hold. I will explore this topic in this post.


Figure 1: typical wellhead set-up for a rod pumping well with the Circulation Loop (on the left side) and the Production Loop and flowline (on the right side). The back-pressure regulator is green and highlighted by the orange arrow.

As can be seen from Figure 1, the back-pressure regulator is installed on the tubing and it holds back-pressure above the flowline pressure. On most wells you will also see a choke on the casing side which can be used to prevent the well from flowing too much fluids up the backside and over-running the tank battery (the well pictured above does not have the casing choke as it is a low pressure well).


A back-pressure regulator/valve works as shown below in Figure 2. By tightening down the spring you can control what the tubing pressure has to be to open the back-pressure valve, and this is how you set and control how much tubing pressure (TP) is being held. But how much should you hold and what is the purpose of the TP?


Figure 2: Harbison-Fischer back-pressure valve/regulator. The spring is screwed in to hold the stem on the seat and adjust how much pressure is required to push the stem off the seat and allow fluids to pass through and into the flowline. Other back-pressure valves (like the Baird brand) have a ball pressed onto the seat instead of a stem, but the mechanics are the same.


The main purpose of holding some additional TP are the following:

  1. To keep any gas that is produced up the tubing compressed and prevent it from "heading" the top of the tubing dry. This is important in keeping the rubbers in the stuffing box cool and lubricated and preventing the packing from burning up and making a mess when it overheats.

  2. The TP allows the pumper to see "pump action" on the pressure gauge and helps him to better know how the pump is performing (i.e. is it effectively displacing fluid each stroke, which is an indication of what the pump fillage is). See Figure 4.


Figure 4: example of great "pump action". Based on how much the pressure is swinging each stroke it appears the tubing is completely full of liquids and the pump has 100% liquid fillage each stroke.


There is one other unique situation that holding additional TP is needed and that is if the well tries to flow up the tubing. This only occurs if the well has a lot of bottomhole pressure to where the pressure differential across the plunger is very small (which can be seen in a dyno card that is very thin, showing little fluid load on the plunger). In this kind of well, if the pump passes a slug of gas through it and that gas unloads the top portion on the tubing, then the pressure differential on top of the pump (the Pump Discharge Pressure) could become less than the Pump Intake Pressure and the well could literally start flowing up the tubing. I've seen this only once and to be honest it was a little scary. The well was a horizontal well around Pecos, TX, with a lot of bottomhole pressure and I could hear the tubing screaming as gas/liquids were flowing off through it. This situation does not happen often and it only happens on high bottomhole pressure wells that can almost flow on there own.

The most important reasons for the TP is to keep the tubing filled with liquids and prevent stuffing box leaks and help the pumper identify how the well is pumping. Now I must say I have encountered many pumpers who think higher TP will prevent gas from getting in the pump; they think the higher TP reduces the amount of gas interference.

As far as I understand, the premise that higher TP can reduce gas interference is not true and I think it is a common misconception. I want to say this misconception is just plane wrong, but I am afraid to speak with outright confidence and say so as I have one customer who currently holds 800# TP on all of their rod pumping wells and when I first checked their wells and told them that the TP was excessive they swore by it and said at one point they had tried lower TP for several weeks and their production dropped. I don't argue with them as you have to do what works best for you (and it is hard to argue with data that shows additional production in the stock tank) but I still question their findings. I wonder if some other factor during that two week period caused production to be lower that was unrelated to what the TP is. After all, it isn't hard to have a couple wells down or acting up that can throw off production numbers, but I point this story out at the caveat to my own understanding.


The mechanics of how the downhole pump operates and what causes gas interference indicate that the TP has nothing to do with how much gas gets in the pump. The increased TP held at surface increases the hydrostatic pressure of the column of fluids in the tubing (which consists of oil/water/gas) but it only has an influence down to the Standing Valve in the bottom of the pump. It does not have an influence below the Standing Valve and therefore it does not affect how much gas gets sucked into the pump, and thus it doesn't affect the amount of gas interference the pump is experiencing. Well actually it does, but the opposite way...


If you are knowledgeable on dynamometer cards and pump operation then you would know that the Traveling Valve in the pump does not open until the pressure in the pump chamber is compressed to be greater than the Pump Discharge Pressure (the pressure right above the pump in the bottom of the tubing). So by increasing the TP you are actually increasing the Pump Discharge Pressure, which means the pressure in the pump chamber has to be compressed higher in order for the Traveling Valve to open. When there is gas interference, this means more of the downhole stroke has to be used to further compress the gas and open the Traveling Valve.


So in actuality, increasing the TP should actually reduce the pump efficiency when there is gas interference! Which is actually opposite of what many field hands think. However, this reduction in efficiency is likely very small (1-3%) and so might be considered inconsequential.


HOWEVER, there is a reason that pumpers have the misconception they do. They think a higher TP reduces gas interference for one reason: because it gives them better pump action on the pressure gauge. The higher TP compresses the gas that is in the tubing and therefore they feel as if the well is pumping better because the pump action is better (if you don't know, "pump action" is basically how much the needle swing on the pressure gauge each stroke).


Pump Action is basically a function of how much fluid is being displaced each stroke and how compressible the fluids are in the tubing. The factors that affect each variable are:

  1. Fluid displaced each stroke: function of pump diameter, stroke length, and the pump fillage/efficiency.

  2. How compressible the whole column of fluid in the tubing is: this is a function of the composition of the fluids, and most importantly how much gas is in the tubing. Gas is compressible; water/oil are not. Also, the volume capacity of the tubing is important, meaning how many total barrels does it hold. So the deeper the pump is set and the larger the tubing diameter, the less pump action you are likely to see with all other factors held constant.

One other factor that affects pump action is a good back-pressure valve/regulator with a good seal. If the seal (ball-on-seat or stem-on-seat) is leaking due to corrosion/chipping, then the greater swings of pressure will have a reduced amplitude when compared to one with a good seal.


The biggest factor that affects pump action is how much gas is in the tubing and what the pump fillage is for that stroke. The compressibility of gas acts as a dampener that reduces the swings of the pressure up and down and it tends to smooth it out.


Another reason I think that pumpers have the misconception they have is that a common way a pumper checks a well to see how well a certain pump is performing is by closing off the valve on the tubing and pumping against a closed valve: they do this and see how many strokes it takes to pressure the tubing up, say from 100# to 500#. If a pump is heavily worn, it will take much longer to pressure the tubing up than if the pump were in good mechanical condition. If the pump fillage is low (due to Fluid Pound or gas interference), then it also will take much longer to pressure up than if the pump had 100% fillage every stroke.


So this test of pressuring up against a closed valve is a way to determine how the pump is doing and this was the most common test performed before modern dynamometers and POC's care around and this test was used to infer what was going on downhole with the pump. Well, if a pump has gas interference that means gas is going through the pump, so we know the fluid column in the tubing is gassified; and if a pumper is holding a higher TP on this well and he pumps against a closed valve he will see the tubing pressure up faster (in fewer strokes) compared to a well that had a lower initial TP. This is because the higher initial TP is already compressing the gas to some degree. [Gas expands to fill its container and by putting pressure on it you compress it to take up a smaller volume, so therefore gas makes up a smaller volume of the tubing with the higher TP.]


So this is another reason why I think pumpers feel like a higher TP reduces gas interference: it all has to do with the pressure gauge and pump action. Pumpers can often be quite stubborn and steadfast in their beliefs, so I have found educating on this topic is often a worthless cause. They know it works better because they see it on their pressure gauge, but that is really just a result of compressibility.


So with all that said, what amount of TP should you hold?


If the TP is too low you can have problems: stuffing box leaks and pumper can't get a feel for how the pump is doing.


If the TP is too high though you can have other problems: increased work load on the whole system (more electricity usage and higher rod loads) and you can run of the risk of also causing more stuffing box leaks due to the high pressure differential acting on the stuffing box packing. Also, emulsion issues can form and create problems at the tank battery. If the TP is 600# and the pressure drops down to 50# when it crosses the back pressure valve, the likelihood of emulsions being created right there due to the jetted turbulence are increased. I know as we had this problem at a lease I used to operate. Once we dropped the TP down we were able to turn off the emulsion breaker chemical we were having to use.


If a well doesn't have gas interference and it is pumped off, I would be fine holding just 60-150# TP. If the well has gas interference, I would hold a little more and in the range of 200-400#. There is no absolute science to it but it might not be ideal if you don't hold any or hold way too much TP. Many old water flooded fields don't even have back-pressure valves, and maybe they don't need to as the well's don't make any gas. Also, the back-pressure valve can be a restriction that can lead to problems with solids/rubbers/paraffin building up on them and potentially plugging off the tubing, so if it isn't truly needed and it could cause problems then maybe you just pull it off and toss it.


One other reason you might need a back pressure valve is if the well is rigged up with continuous chemical treatment as shown in the figure below. A small amount of chemical is injected each day down the backside (maybe 1/2 - 2-gallons) and some produced fluid is needed to be used as a vector to help carry the chemical all the way downhole to the pump intake. The pump might be set 2-miles below the surface, so flush fluid is important to help it get all the way downhole. Without the flush fluid the chemical will just dribble down the casing walls and it can dehydrate and junk up (as one chemical technician told me).


Figure 5 A,B: continuous chemical set-ups on wellheads. Chemical injection line connects to the chemical tank and the slip-stream connects from the tubing to the casing to circulate a little produced fluid to help carry the chemical downhole to the pump intake.


In order for the flush fluid to slip from the tubing to the casing through the slip-stream, there has to be some pressure differential acting across it to push it that way. If you don't have a back-pressure valve causing the TP to be higher than the CP, than why is the fluid going to go that way? It might as well just pump down the flowline. So you need at least a little pressure differential here to force the flush fluids down, and that is another reason for the back pressure valve.


So do you agree or disagree with my opinion on the function of the back pressure valve? Leave a comment and and let me know what you do in your field and let me know if from your experience, the higher TP on gassy wells actually increases the production (or does it just increase the pump action). Cheers!




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