Replies to This Discussion

Permalink Reply by Mark on May 3, 2019 at 7:58pm

Chaz - your wife is basically more correct on this issue. The "water hose" here is the size of the production casing (usually 5.5").

Assuming all things are similar as to landing zone, how a well is frac'd and the choke size on the surface, laterals of different length will produce at similar rates initially (with the longer one being a bit better). The difference between the two is manifested over time in that the longer laterals should have a lower production decline profile and will make a higher EUR over time.

There are different trends for different areas, but a good "norm" for what a 10,000' lateral will do is about 1.75 times the EUR of a 5000' lateral.

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Permalink Reply by Chaz on May 4, 2019 at 12:08am

Well, let's not tell her she was more correct! Lol! It does make sense and I was hoping it meant a longer "well life" if you will. Thanks as always for you response Mark, really appreciate it!

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Permalink Reply by James C. Maxwell on May 4, 2019 at 9:44am

This is interesting.  Seems as though there should be an electrical engineering analogy, with currents (oil flow into production casing on the one hand, and oil flowing out at wellhead on the other), capacitance (volume of well pipe), and resistance (headloss from oil flow).  I'll try to work on it, though I'm a bit rusty on doing these sorts of things.

People worked out this kind of stuff in the 19th Century with the propagation of telegraph pulses down a telegraph line, i.e., pushing down the telegraph key (fracking) and seeing how the electrical pulse traveled down the line.  Resulted in a set of equations called, not suprisingly, the Telegraph Equations.

Glad we have Mark's actual field experience with this.

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Permalink Reply by Chaz on May 4, 2019 at 11:26am

Wow John, I had to take a Tylenol after reading that reply! LOL! I'm afraid that analogy is above my pay grade but I do get the gist of it and I am curious to see what your research provides. CHK has not published the Initial Production numbers on the RRC site as of this morning but I think I will find the numbers are slightly higher than the initial wells. I say this based on the production shown on my Feb check stub. Some wells had 10 days production and other 2 or 3 days. All were turned on at some point in Feb...18th, 25th, and 26th. Thanks for your reply. Give me an update when you've completed your research. Chaz

Mark,

Thanks again for your reply; my wife is still smiling about the fact she was at least on the right track. 

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Permalink Reply by James C. Maxwell on May 4, 2019 at 6:16pm

Chaz

We all cede things in marriage.

Some of us low-brow types take out the garbage, empty the dishwasher, etc., to keep peace and love in the fambly.

Others, such as yourself (probably in addition to the above), acknowledge that your better half can intuitively solve partial differential equations in her head more quickly and accurately.

Ah, the Battle of the Sexes.

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Permalink Reply by Roger Neal on May 5, 2019 at 5:03pm

Well here is a reservoir engineers view....and complimentary info to Mark's reply...

the key to unconventional rate and EUR depends upon many key elements....and all those elements come together in a performance metric called "stimulated rock volume".

What defines "stimulated rock volume"? total length, number of frac stages, number of clusters, spacing of stages, volume of stimulation fluid pumped per foot, volume/effectiveness of frac proppant pumped per foot, (and other factors) and somewhat last, but certainly not least... the trajectory of the lateral being kept within the optimal hydrocarbon saturation of the layer/bench.

There are certainly examples from some operators where shorter horizontals have provided a higher rate (and likely higher EUR) compared to a longer nearby lateral. 

My point is not to argue that longer isn't better, but rather just to point out that it takes many things that designed properly and then executed together well (and NOT JUST LENGTH), to yield a better well.  

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Permalink Reply by Mark on May 5, 2019 at 11:22pm

Roger, thanks for your comments on this issue from the PE perspective. I am sure that improved frac stimulation approaches (e.g. Gen 4 vs Gen 1 thru 3) can lead to better initial rates and EUR's - even for laterals of similar length.

My experiences with horizontal drilling and "shale" plays has taught me that this whole drilling / completion / production process is like playing some sort of "Vulcan" chess (but with 25 or more dimensions to consider)!

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Permalink Reply by Chaz on May 6, 2019 at 8:12am

Thanks guys for chiming in on this issue. I find it all very interesting; albeit at times a little confusing at first read.

Hopefully the improvement in the entire process will be evident in these new wells. Again thanks to each of you for sharing your much appreciated thoughts! 

 

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Permalink Reply by James C. Maxwell on May 6, 2019 at 1:24pm

Chaz.

My first attempt at an electronic analogy produced some, but not all, of the behavior that I was trying to model as to the IP of a well.  I think I had the capacitor (equivalent to filling the production piping with oil before flow to the surface) in the wrong configuration

Being stubborn, I'll soon embark on a different circuit configuration to see if that works.  Thanks for the challenge.

Later.

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Permalink Reply by James C. Maxwell on May 10, 2019 at 6:36pm

Now, this is ONE INTERESTING problem to ponder, Chaz. 

I, shamed like a dog with his tail between his legs, report that my electrical analogies to model horizontals of different lengths did not work out.

However, applying some elementary fluid dynamics to the situation, you get some interesting answers.  Of course, all this is based upon idealized conditions about the reservoir’s uniformity and permeability along the horizontal, continuous and uniform permeability of the pipe and not discrete fracking with stages as in the actual case, relatively constant reservoir pressure during the time scale of interest, etc.  Setting up and solving problems like this is usually easier to do with continuous variables rather than discrete (fracking stages, e.g.), and I was surprised to get a “closed-form” solution, albeit steady-state, which does not show the transient effects of the onset impulse of flow (IP).

As the oil flow accumulates along the length of the horizontal from the last (furthest away take point) frac to the first (nearest take point), being an incompressible fluid, it has to go faster and faster.  As a result, the pressure drop per foot along the horizontal increases (but not in a straight line).  This means that the highest pressure in the horizontal occurs at the last frac and the pressure rolls off at a faster and faster rate as you go toward the first frac.  Because of this, the flow of oil per foot into the horizontal, proportional to the square root of the pressure drop from reservoir to pipe interior, increases as you go from last frac to first.  There can never be (in idealized circumstances) as complete drainage of the area at the last frac as at the first.  Mark, some of this may be behind your rule of thumb about a 10K ft. horizontal producing approx. 1.75 that of a 5K ft. horizontal, and it may impose some kind of limit on desired horizontal lengths when reservoir pressure and EUR are taken into account.

The calculations result in an extremely complicated function of reservoir and pipe permeability (the latter an idealization of discrete fracs as continuous pipe permeability), reservoir pressure, friction factors for flow through piping, depth of the well, etc.  I have not modeled the decrease in reservoir pressure with time, but only looked at this for a time period during which that remained constant.  For a doubling of the interval from first frac to last frac, the production seems to increase, which makes common sense, but certainly not double.

Superimposed on all this, as Mark and Roger have pointed out, are the real-life characteristics of the reservoir.

In all seriousness I’d love to hear the comments of Mark, Roger Neal, or anyone else, even if you totally destroy my ideas presented above.  I’m wrong more than right, but guys who hit .250 in the majors make zillions.  If only that were the case for us pitiable royalty owners.

 

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Permalink Reply by Chaz on May 10, 2019 at 9:53pm

Wow, I'm glad I asked the question! The replys have been very informative make for extremely interesting reads! One factor I failed to mention that may need to be plugged into the equation is that gas is being pumped back down hole. I have no idea as to volume but I'm sure that will effect flow as well. I have no idea how that process works but is gas pumped down to the end of the well bore to push product back to the surface?   CK

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Permalink Reply by Mark on May 10, 2019 at 10:45pm

Sounds like you are describing "gas lift". This is a common artificial lift application that helps unload the fluids from the well bore / lateral instead of just letting the well try to produce under its own energy.

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