Fluid Level Calculation in CBM Wells 1

[grcontrol]

In Order to estimate the fluid level in CBM's wells, without using downhole sensors is possible say:

Fluid Level = (Pr -Q/j - Pcasing)* 2.35
Where J and reservoir pressure are known and they can be considered the same during definited time
Is possible to say that the Pump Intake pressure = bottom flowing pressure just to estimate the fluid level?.

My question is. Can I estimate the fluid level using those assumptions?
Thank for your help

 

[zdas04]

I have never found any surface correlation (or fluid-level shot) to approximate liquid level in a CBM well. I've looked at hundreds of flowing pressure bombs in coal wells and they always look really strange. 0.22 psi/ft gradients above 0.001 psi/ft gradients are really common. 0.43 psi/ft gradients are very uncommon.

We've compared casing pressure to reservoir pressure to flowing tubing pressure many times and the results are just all over the map.

The formula above can be affected by skin, scale, liquid hold-up, and most of all by turning the 1/0.43 psi/ft gradient into a froth.

I sure wouldn't make any investment decisions based on that equation.

David Simpson, PE
MuleShoe Engineering

http://www.muleshoe-eng.com

 

[nonAPI]

grcontrol,

You may be able to estimate it that way if the well is not flowing. Once you start moving gas all bets are off. As Mr. Simpson says, "froth". About the best you can do is base it on experience with wells in the area and even then it's a guess.
I know of a well that will make about 1 MMCF/day and very little water without the pumping unit running. If you start the pumping unit you make about 1000 bbls of water and 2MMCF/day. Since the pump cannot pump that much the gas flow up the annulus carries the rest. Where do you call the fluid level on this one?

Is this a hypothetical situation or are you trying to solve a problem in the field?

Cliff

 

[grcontrol]

Thank four your comments

This is a hypothetical situation. As you know, the principal problem in CBM is the fluid level in the casing which is needed to protect the pump ( any pump).
The installation of the downhole sensor is expensive in most of the cases, and I'm just trying to find a way to avoid the using of this sensor and estimate the fluid level to protect the pump.
Maybe I'm discovering the wheel, and everybody know that it isn't possible to estimate it, but I'm still looking for some control logic that can help on this matter
I'll looking for of your comments

Giulia

 

[dadfap]

grcontrol

why not just set the pump below any perforations or coal seam fractures.

offloading the hydrostatic is what allows gas to migrate to the well bore. if you pull down to around the level of the perforation you will get max gas rate and unless the fluid velocity is high, all the gas should migrate to the top of the fluid level.

If this is a submersible then it should be shrouded to provide cooling for the motor.

If it is a rod pump, then any gas locking is taken care of because there "should" be minimal gas below the fracture / perforation.

I installed some CBM ESP pumps for Enron once........... and I did get paid!

hope this provides another alternative for you.

All the best

dadfap

 

[nonAPI]

grcontrol,

I have to disagree to some extent. The principal problem in CBM is to convince the company to spend the money to drill a sufficient amount of rathole to enable the pump to be set +/-75' feet below the perforations and still have rathole for solids to collect in. The benefits of dropping the fluid level below the perfs cannot be overstated.
In practice, there are some operators in the PRB who inject gas down a small diameter tubing run down the well and when the pressure levels off on the tubing they use that figure to calculate the hydrostatic load on the casing so they can regulate the ESP. They are trying to protect the pump also but do it by hydrostatic pressure rather than fluid level. This accounts for "froth".

What are you doing to protect pumps now?

Cliff

 

[grcontrol]

Right¡¡. Now I've adjusted two controls in the VSD: PID control using downhole and surface measurements to calculate the fluid level, the pump speed is changed to maintain that level. Also low load control, adjusted following the pump manufacture curve, if the pump load is below to the load of the adjusted, at specific speed, then the system is shutting down because probable the pump is working without flow.
As Clif said, normally we found those problems when the pump is already installed and the control system is never designed when the well preforate or completed.
I'm working in some logics, I'll send you a new e-mail with those logics, to see what you guys thing about it

Thank very much

Giulia

 

[zdas04]

RAT HOLE AIN'T THE ANSWER. Sorry about shouting, but I couldn't be more serious. I had 10 wells with over 100 ft of rat hole. In every case I set the pump (rod pumps and PCP's) way low in the rat hole. In every case, I lost gas over setting the pump in the lower 1/3 of the perfs (or the most productive seam in open-hole completions). Further, the pumps failed earlier from ingesting solids.

I've found that "the benefits of dropping fluid level below the perfs" is often overstated. I've spent a bunch of time trying to manage fluid level in coal wells to an optimum level and that optimum is always an intermediate level within the most productive seam. If I dry the seam out completely, I lose gas. If I flood the seam I lose gas. If some portion of the top of the seam is dry and the bottom is under water, I make the most gas.

The dynamics of low bottom-hole-pressure lift are very counter-intuitive. We shot fluid levels with the pumps high and low and our best intrepretation of the jumbeled up data was that setting the pump really low resulted in higher fluid levels (I know, doesn't make sense, but it happened in 10 out of 10 wells).

One pump-off control scheme that worked in the San Juan (in a conventional well) is a dual-probe flow-sensor (I don't remember the name of the company). One probe is heated, the other is an RTD. They are a known distance appart so it is an "easy" thing to calculate how much heat is carried away by gas flow and by liquid flow. When the RTD temp starts to rise, the PLC slows the pump down, when the temp falls, it speeds the pump up. This technique has worked well in a conventional well, but the "froth" we got to surface in coal wells had about the same thermal characteristics as gas.

David Simpson, PE
MuleShoe Engineering

http://www.muleshoe-eng.com

 

[nonAPI]

Zdas04,

Now, don't take me wrong here. I am not trying to tick you off. When I don't understand how a theory can be correct I have to challenge it. I'm not challenging your results. You were there I wasn't. I don't buy the interpretation of how the results were achieved. If I knew how to make the font smaller I'd whisper. (LOL)

I never said set the pump way low in the rat hole. I said set the pump at least 75' below the bottom perf. The rat hole needs to be at least 250'. When I say the pump I'm actually referring to the intake into the bottom hole assembly which is set up to help drop out solids also.

In order for me to believe that the pump would wear out slower being set in the lower 1/3 of the perfs rather than below the perfs because of less solids intake I'd have to believe: 1-It would wear out only 1/3 slower as 2/3 of the solids are still passing it going to the bottom of the hole. 2- That none of the solids entering the wellbore from the lower 1/3 of the perfs are "floating" around above the level they entered due to turbulence. 3-The pump was set too near the bottom of the rathole. 4-The bottom hole assembly was not very helpful. I can buy #1. What kind of life extension did you see? I don't buy #2 at all. I can buy #3 and #4.

I don't buy the theory on dry seam, wet seam at all. If you lose gas from the most productive seam when it is dry and you lose gas if you flood it then why do you not see a loss of gas from the top seam (because it is dry) and a loss of gas from the bottom seam (because it is flooded) when the middle seam is in a partially wet, partially dry condition? Why would the wet/dry theory apply only to the most productive seam? There must be a different explanation.

With the pressure bomb variations you have seen how do you even decide what is wet and what is dry? I have to believe that only in the lowest gas volume wells could you even come close to figuring it out.

Were your fluid level shots in wells with strong pumps or with pumps fading or both? Did water production increase after the pumps were moved uphole? As you say, it doesn't make sense that fluid level would fall when the pump was moved uphole. The only way it could fall is if, for whatever reason neither of us are seeing, pump efficiency increased in a more gas cut environment. Were there across the board gas volume losses when the pumps were initially moved below the perfs and the pumps were still strong?

You have me intruiged as to what the explanation is. What other thoughts do you have as to what it could be?

Cliff

 

[zdas04]

Cliff,
When I still worked for BP, we had a sign on the team-room door "... Coal Where Every Day is a Whole New World". It took a long time, but we finally realized that wishing the Coal would make sense or be logical just wasn't going to make it happen. Every wierd thing I saw in 11 years with the coal caused me to develop an hypothisis to explain it, then I developed interventions to address the hypothisis. Some of them worked, most didn't. You can get a flavor of this process at my web page under "Samples" and look at "Producing Coalbed Methane at High Rates at Low Pressures SPE85409". I'm presenting this paper at the SPE ATCE next week in Denver (the last talk on the last day, I'll probably be presenting to the moderator) if you're there look me up (I'll be sitting in Booth 2105 most of the week).

BP has a half dozen new wells with over 200 ft of rat hole and they all do worse when the pump is set (even slightly) below the coal. I don't have an explaination, but that is what we found.

One thing that is very different about the coal is the very low bottom-hole pressures that are required. These pressures increase the amount of water vapor that can be carried with the gas. At 20 psig flowing bottom-hole pressure and 105F bottom-hole temp, you can carry over 8 BBL/MMCF of water as water vapor. As you go through the upper aquifer the temp drops and you get rain in the casing. The complexities of this flow are horrible.

Then you add a pump and the gas is still at 100% relative humidity. But if the inflow is 6 BBL/MMCF, and the evaporation is 8 BBL/MMCF, and the pump is moving 20 BBL/MMCF then the water level should go down. UNLESS getting the water level down causes the WGR to increase dramitically. We (BP that is, I don't work there any more) have video that, while far from conclusive, suggests just that. So maybe my "lower 1/3" rule of thumb is enough to prevent draining the nearly-infinite water bucket that the coal seems to be. Water is a waste product and our business doesn't value data, so none of the operators here have ever gotten meaningful water data and I can't tell you if the water rates went up, down, or stayed the same when we changed set-depths.

Coal fines are really interesting besties. The average cross-sectional area is less than 5 microns. They will flow through anything. The coal (at least San Juan Fairway coal) is very soft (friability averages less than 15 psid) and it breaks continiously. Every time it breaks, it creates what I call a "fines bloom" that puts hundreds to thousands of pounds of coal into the flow stream. The fines all have a very slight positive electrical charge and they repel each other. Any sort of downhole pump will build a small (or maybe not so small) electrical charge just from metal rubbing against metal. As the gas/water/fines mix passes the pump on the way down the rat hole some of the coal fines lose their positive charge to the static and pick up a negative charge. At that point the coal clumps and plugs things like pump-intakes very rapidly. I estimated last year that BP's 60-70 fairway wells put 600-1000 pounds of coal into the gathering system each week (based on what we shoveled out of pig receivers). 2-3 pounds will seal the intake ports on an ESP, PCP, or rod pump. Setting the pump higher reduces the effective size of the electrostatic precipitator that a moving pump downhole becomes.

My favorite artificial lift method in the coal is an eductor. I've run over 30 eductors for over 5 years with really good results. The interesting thing about using an eductor is that it will slurp whatever is at the end of the tubing - it doesn't care if it is pulling on liquid, gas, or a slurry and the NPSHr is less than zero. Consequently, we find a solid water gradient (close to 0.43 psi/ft) just below the tubing. With eductors we've been able to move tubing up and down to find the level where gas production is maximized. That makes me pretty confident that something unpleasant happens when you try to pull the coal dry. I can't tell you with confidence what it is, but it is ugly.

David Simpson, PE
MuleShoe Engineering

http://www.muleshoe-eng.com

 

[nonAPI]

Mr. Simpson,

Wow! What an information laden post. Thank you.

I must agree that CBM is a whole new world everyday and the challenges tickle the brain. Now if we could get people to look at some oil fields with the "open to new procedures" approach that CBM dictates (like that will ever happen).

Almost all the experience I have has been with CBM has been in the Drunkards Wash field. Very different, it would seem, from the San Juan. Coal fines cause very little problem with production equipment there. It has not yet reached the low pressures you have dealt with. There has been much speculation on how production parameters will change as pressure decreases.

Our business does not value data because most can't see how one factor can explain so much about why 10 others factors are reacting the way they are. It's also costly to compile for the few who will use it. Besides, where is the job security if you don't have to start from scratch trying to figure out the problem instead of building on what you learned before?

If I rememeber correctly an eductor is what we call a jet pump in the field isn't it? To my knowledge no one has tried one in Drunkards Wash. It is beyond time for a test even if for information gathering only. However, due to the life span of the rod pumps and rods and tubing (provided they keep corrosion under control) they experience it would probably be less economic. There are instances they should consider it, though. What have you found for economics as compared to rod pumps?

How long after a pump setting depth is changed does the gas production volume react upward or downward? Perhaps the "bubbling" action of the water and gas moving through the cleats is the only thing keeping the fines moving. So if the seam is dried out the fines are what is plugging off the gas flow. Perhaps the gas breaking loose/through from the coal is enough to create fines which, if no water flow is present, have nowhere to go. And, who knows how many other factors are creating fines. I'd have a hard time believing the increased humidity could slow the gas flow appreciably. I move slower by the time I get to Kansas City, though. (LOL)

I have read or been told that there have been some laterals drilled in CBM wells in the San Juan. Any knowledge on these and what they have shown for advantages/disadvantages? Seems like I read they were trying a Pinnate pattern there also.

By the time you read this the Moderator should be well informed.

Cliff

 

[zdas04]

Cliff,
The reason that I keep pointing folks towards studying the San Juan is that the San Juan Fairway is a true microcosm of a coal field. We went from 1,500-1,800 psig reservoir pressure to 40-150 psig in 12 years - and produced a couple of TCF of gas doing it. The paper I presented on Wednesday covered most of the high points of this pressure traverse, too bad the moderator really was the only one there. We went from high-pressure (i.e., operations consisted of changing charts twice a month and cashing large checks) to transition (i.e., the incline was over without ever being adequately described and some wells were on a 70-80% decline) to low-pressure where everything is special.

The current crop of coal fields will go through all of these stages in a more leisurely manner. If I was starting a Drunkard's Wash project today (to say nothing of Hungary, Australia, India, or China) I would build the facilities to work with the San Juan late-life model. All new separators would have integral blowcases (PESCO in Farmington, NM has a really nice design) even on wells that don't currently have compressors to drive a blowcase. I’d lay multiple lines from the well to the production equipment and start with a 3-ball manifold for a compressor (standard size with flanges set in a standard configuration). All gathering lines would be piggable or have a Vortex tool. And I would make sure that there are plenty of places to tie in water and/or chemical trucks to flush phase-change scales. All of these things are reasonable to install and very expensive to retrofit.

The coal we see to surface in San Juan (like most things here) is a function of the friability of the coal. With 15 psi friability any dP will cause the coal to fail and fines to bloom. Most coals are harder than ours and don’t fail as readily. But they still fail and you still get solids moving.

The argument between porosity being reduced by the overburden pressure and the porosity increasing because of the reversal of the coal swelling from desorbing gases is interesting and quite pointless. Many studies have shown the c(p) “constant” in the AOF equation changing in the San Juan by as much as 30% per month. If you have a decent material balance, you could do the same calculation and see how your constants change with time. If they go up, then the matrix-shrinkage camp wins. If they go down, the over burden camp wins. If they’re really constant then you probably didn’t take your measurements closely enough.

Eductor’s are in the same family as jet pumps, but they are pretty different. The thermo-compressor industry uses the term “eductor” to mean a thermo-compressor that is driven by a liquid. An “ejector” is a thermo-compressor driven by a gas. Oil & Gas uses “eductor” as a surface device and “jet pump” as a downhole device. The “eductor’s” I’ve used successfully in San Juan are designed as “ejector’s” (the biggest difference is that for compressible flow the throat is shaped differently) and use the discharge of a compressor to pull a known amount of gas up the tubing while the majority of the flow is up the backside. As you might imagine, the known volume is well above the critical unloading rate of the well. Most of the time the tubing is running 3-10 psi lower pressure than the casing on eductor wells. The biggest benefit of an eductor (besides price, they cost under $2k installed) is that it has a zero NPSH. Look at the design of an API standing valve – 61% of the effective area of the ball is above the seat so it takes 75-100 ft of water above the pump to open the standing valve. The normal condition of a rod pump below 50 psig flowing BHP is gas locked. Nothing happens quickly in the coal. Two to six weeks is about right to approach a “steady state” flow.

There have been a few attempts at horizontal wells in the San Juan coals, some of them have been very well publicized. The most common result is a collapsed hole and very little production. I haven’t heard of a successful horizontal well in the Fairway. The multi-lateral wells were all the rage for a few weeks, then everyone went sooo quiet. I think they might have collapsed into a courtroom drama.


David Simpson, PE
MuleShoe Engineering

http://www.muleshoe-eng.com