Replies to This Discussion

Permalink Reply by Dion Warr, CPL on April 17, 2014 at 11:12

Larry S:

Initial pressures start as a function of depth (force generated by overburden) as well as formation pressure.  Where sufficient organics are present and pressure and termperature conspire to cook those organics into the gas phase, pressures can exceed those of the surrounding rock, which results in overpressure locked within the formation.  Reference numbers and conversion factors vary somewhat, but 0.435 psi/ft seems to be a reasonable figure for overburden pressure.  In this scenario, the Mondello well near the SE portion of the fairway (relatively deepest portion of the play tested) was shown at IP with a 9637# CP at 13768' TVD - assuming this was a "static pressure" at initial test, this would represent  3647# of formation overpressure above the expected baseline pressure of approximately 5990#.

As to your point re: trapped pressure from frac, this is possible, but assuming the frac was successful, the effects of the frac job would create permeability on a macro scale which would serve to communicate products to the wellbore that would closely track pressure within the formation, which should serve to any artificially generated pressure to dissipate rapidly.during flowback.  Eight months after initial tests, DT-1 data showed pressure (flowing) at 8800# with flowback rates (no more than total water produced) down to approximately 1/5 that at IP, with cumulative production of approximately 2 BCF at that time.  It would appear therefore that much of the overpressure was likely generated within the formation prior to the start of well operations.

Choke settings were implemented for a variety of reasons - takeaway capacity as well as time and cost-benefit analyses for maximum drawdown vs. steady depressurization to conserve formation integrity and protection against damage.  Pressure maintenance became the norm after production data and EUR curves appeared to support chokes (in terms of 64ths") in the 14-18 range by and large (initially operators were implementing chokes above 20 and more in the range of 24-28).

This is a "quick and dirty" analysis, and by no means a qualified opinion (not a geophysicist or reservoir engineer), but based upon what I've seen and pulled together from discussions (and here!) 

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Permalink Reply by Larry G Smith P.E. on April 17, 2014 at 11:37

Thanks for the reply but I do have a question, if BOP were that high, why has the pressure dropped off on a steady decline? The pressure  on our section was  6647 psi at start,  now 928 psi. If the pressure was as you say, why does it drop so much. The pressure that is now is more like the formation pressure.  I  work in the Oil Patch, have been for over 50 years and still going. I see many different types of production mostly from vertical wells that are drilled into very porous formations that did not need fracing and yes, the pressure from these formations were built up pressures and as the well produces, it will have pressure drop but over many more years than the HZ wells. I still contend that the large pressures  seen in these wells when first drilled and produced are a direct result of the frac pressure used to open up that production tube. The gas produced had a much lower BTU rating due to this washing effect.  I am not a geophysicist or reservoir engineer but I am an Electrical Engineer for 52 years and all of it in the oil patch.

 

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Permalink Reply by Dion Warr, CPL on April 21, 2014 at 6:51

Larry S:

Speaking not as an engineer but as an observer with some analytical skill and a math-science inclination, there is an inverse proportionatlity between pressure and volume (imagine, if you will, production related to expansion of the volume equal to the displacement of the removed product).  Conventional reservoirs tend to deplete logarithimically, which translates to a linear graph on a semilog plot (again, qualifying, this assumes an ideal gas situation which does not entirely account for a range of liquid/vapor and gas product which must necessarily incorporate differential rates of flow from the formation as well as account for energy and volume losses due to change of phase).  An unconventional well will generally follow a hyperbolic curve which only begins to flatten on semilog plots as the created porosity and permeability approaches the actual porosity and permeability of the source rock.  So, theoretically, given a good frac job (no pressure losses due to screenouts, etc.), and proppant levels sufficient to create adequate flow within the "cylinder", mechanical overpressure for the frac should be relieved almost immediately, as water (the primary medium for the frac) is practically incompressible - very little voume would need to be produced upon flowback to equalize that pressure, and the remaining water would be flowed at ambient BHP along with product.

In a conventional reservoir, permeability would be a large enough value so as to form a suitable replacement volume at pressure such that reservoir pressure declines translate more or less instantly across the pay zone - in the unconventional reservoir, this replacement becomes less and less instantaneous within the "cylinder" as the proportion of gas molecules located in situ are progressively further away from larger frac spaces - these gas molecules, being more "trapped", cannot replace produced volumes at pressure as quickly - thus BHP drops precipitously until the formation pressure differential is sufficient to "squeeze" gas from the rock into the frac space.  This should result in a hyperbolic depletion graph (less a line on semilog plot and more of a steep initial curve which tend to flatten and approach an asymptotic flat decline line with a negative slope.

I would theorize that this induced "back pressure" on the formation would serve to increase the likelihood of formation damage as the differential between BHP and "formation pressure" increases - similar to what is observed in conventional wells that are "pulled too hard" - it would appear to me that increases in EUR associated with HA wells placed on lower choke settings (greater choke - smaller aperture) likely is due to minimizing this differential - but again, this is not my wheelhouse - G&G or a reservoir engineer would be better to speak as to this issue.

Similarly, I would much rather rely on a geologist or geophysicist to explain the "washing effect" to which you refer, other than from a chemical perspective, NGLs with longer carbon chains and more nonpolar covalent bonding would be expected to be more hydrophobic than its lesser encumbered methane cousin (which will at least form intermediate hydrate species with water).

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Permalink Reply by dbob on April 21, 2014 at 7:43

Yeah, what Dion said.

Permalink Reply by jim weyland on April 21, 2014 at 7:46

i'm an oceanographer by education. accordingly, please consider my comments, below, in that knowledge.

i've seen many, many gas analyses from all sorts of wells, gas and oil. in my experience, a well's gas make-up, the mol%'s of each constituent, stays fairly constant throughout its productive life. 

and, with respect to a well's formation pressure(s), its my guess, there's another factor to consider.  that's, whether or not the well's 'gas' is subject to adsorption w/the formation rock. note: i know that i can happen, but i have absolutely no idea if its a significant factor w/shales.

p.s. we aggies really relish opportunities to use $0.50 words like adsorption. thanks for the opportunity.

Permalink Reply by Dion Warr, CPL on April 21, 2014 at 7:56

Jay:

The conventional wisdom is generally that hydrogen bonding does not occur within CH4 (insufficient polarity of the C-H bond to create the interaction).  However, CH4 trapped in hydrate shows up in greater quantity than one would expect via clathrates (basically, small geodesic "water cages" formed at standard pressure at low temperature), and other chemical interactions suggest a different mechanism.

This is one abstract and another - but may be worth grabbing if you have the access via your credentials.  Clathrates are typically size dependent, and larger molecules requires larger and larger cages which water molecules are less and less wont to create - but the possibility of a transient CH5+ (aq.) species creates a large enough window to bend the conventional wisdom and still respect the laws of chemistry and physics.  The second abstract I believe speaks louder to the existence of coordinates of CH4·(x)H2O at higher temperatures and pressures.

And with that, I have exceeded the quota of my use of my undergrad degree while being a landman.

Permalink Reply by Skip Peel - Mineral Consultant on April 21, 2014 at 7:46

Me too.  LOL!

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Permalink Reply by Hopeful About Natural Gas on April 21, 2014 at 10:27

Whew! This discussion went far over my head, but it's really good to read the about the technical aspects that I know nothing of.

What's the bottom line for the Haynesville??

Also, check the top of the page: NG at $4.75 and up almost 5% today! What gives, since winter is about over???

yeah, I'm still somewhat hopeful ...

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Permalink Reply by Skip Peel - Mineral Consultant on April 21, 2014 at 10:30

The next benchmark price to look for is the monthly settlement for May.  It should be published by the first of next week.

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Permalink Reply by Spring Branch,mineral owner on April 22, 2014 at 4:25

Where is it actually published, Skip.  I usually just try to guess at it based on the price the last Thursday of the month.

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Permalink Reply by Skip Peel - Mineral Consultant on April 22, 2014 at 4:32

Here is a link.  The next month settlement is usually posted in the last few days of the preceding month.

http://gsfi.net/common/NYMEXSettlementHistory.pdf

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Permalink Reply by jim weyland on April 22, 2014 at 4:48

here's another link to the cme ng contract. there you'll see the contracts' prices on a 15 minute delay basis:

http://www.cmegroup.com/trading/energy/natural-gas/natural-gas.html

if you root through the links on that page, you can find out just about everything about the contract.

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