Water as a problem in a gas well - second attempt to get a discussion from some experts...
Hi Folks,
Okay, I attempted to ask this question before, and got no takers, either because no one really knows, or there is something wrong with the question. So "my" well in the corner of SE RR Parish - 240843, s7-12n-8w, is finally in SONRIS today, and the IP looks better than I was expecting from previous discussion, but there is a LOT of water; the initial stats in the 11/15 entry:
COMPLETED 9-1-10; GAS HAYNESVILLE RA; 8408 MCFD; 20/64 CHOKE; 1680 BWD; 7725# CP; PERFS 13,428-17,260' MD.
So for being near the edge of the play, it is producing at about half the rate of the pretty darn good wells, but of course less than that compared to the barnburners. But the thing has got lots of water - 1680 BWD - but is producing nonetheless. So I found a book on the subject of remediating gas wells that have water seepage, so folks have put thought into this (I didn't buy the book, just noted it is a discussed subject - I am not a petroleum engineer, though I find the topic pretty interesting). My question, basically, is "does anyone know how water in wells in the HS is being handled, and overall, is there a reasonable prognosis for a well like this, or most likely is it going to silt up and be dead in 3 mos?". Encana seemed to think it was something that could be worked on, based on a discussion in the RR Parish forum. I am just thrilled that Encana was willing to wander out on the edge there, and actually found something; the PHK super-maps were not particularly encouraging for this area at all for HS production. If the water can be dealt with, it would seem we are approaching economic viability for the O&G company on a well like this in the $5-$6/MCF price range. Anyway, I am basically trying to get some speculation from the many folks out there that know more about horizontal shale wells than I do...
Views: 254
Replies to This Discussion
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Permalink Reply by Spring Branch,mineral owner on
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Typically the water being produced in the Haynesville is the frac water which was used in the fracing process being returned with the produced gas. It is a part of the "cleaning up" the well process and is a good thing. This well in Section 7 of 12/8 certainly seems to be a much better well than the well in Section 5. It actually aoppears to be a pretty decent well.
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Permalink Reply by Les Bamburg on -
Robert, as SB said this a fairly typical water rate for the initial flowback of "frac" water. This is one reason most HS wells are initially completed and produced without production tubing. After the water rate drops in a few months EnCana should install the production tubing.
In the longer term EnCana plans to install a system for re-using the flowback frac water in frac'ing later wells.
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Permalink Reply by Robert Duke on
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So I guess maybe something earlier confused me (imagine that!), but I have seen a number of wells on the fringe, low production, lots of water, and folks have said "Uh oh..." (I am thinking that Jack Black was perhaps who I last saw saying something like this in reference to something practically in Arkansas; I read Jack's postings as a combination of information and humor). Anyway, so for most wells out there, they don't seem to bother to post any "barrels of water" figure on completion, and I just presumed that meant there was not much, and when they did post it, it is a potential problem. What I am hearing you say here is it is more a matter of completeness of reporting? Correct? I did do some reading, indicating that seepage of non-frac water into gas wells will limit production and eventually require remediation or kill the well. As an aside, Les, I know you have been looking at this corner of the play for indications of what it will do - do you have a better opinion now - or do we still need a bunch more data? Encana comments sounded to me like they are constantly working on improving their results under different conditions (got to love those guys). I am also holding out some hope for the Bossier, but not really expecting much until gas prices improve. Boy, talk about killing yourself with your own success!
Best Regards - Bob Duke
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Permalink Reply by Les Bamburg on
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Robert, you are correct that high water production in a conventional well/formation can be an issue as the source is from the formation itself. In such situations the water production rate increases with time and can eventually "load up" or "water out" a well. The former can potentially be remediated but the later indicates the gas-water contact has moved up into the well and probably means the formation will no longer be productive in that well.
The low permeability of shale gas formations means there should be little or no water produced from the formation itself. Issues occurred during the early stages of the Barnett Shale in some areas because operators frac'ed into a conventional formation below the shale that contained formation water. Operators in the Barnett Shale have improved their techniques to avoid such problems.
I am still trying to assess the Haynesville Shale in your area. I am certainly encouraged by your well as EnCana could probably have tested at 10-15 MMcfd with a slightly larger choke size. I would like to see the results from a couple of wells in the area that have been completed and put on production.
Also, I have not seen update from EnCana/Shell on the Bossier Shale potential in this area.
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Permalink Reply by Robert Duke on
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Hi Les,
Okay, thanks very much for the input (and from Doob and SP); sounds like there is reason for at least some optimism; more data to collect though :-)
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Permalink Reply by Doob on
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Your water rate is typical. It should drop to a few hundred/day after about 10 days or there is probably a problem--like a fault--that will have a negative impact on the reserves.
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Permalink Reply by little ole 1st grade teacher on
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Exactly how does a fault impact wells? I have been told that faults are a plus and then I have been told that a fault is a negative? Which is it, a plus or a negative? Or can it be both?
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Permalink Reply by Les Bamburg on
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LOFGT, faults can be an issue as they could potentially limit the length of a horizontal lateral. If operators are aware of the fault location, the horizontal lateral can be drilled in a direction to avoid the fault.
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Permalink Reply by Robert Duke on
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Okay, plowing around, I figured out on sonris that there are a lot of wells with entries in the "well tests" column - seem to be of two types. The SDM2G entry seems to correspond rather well with initial test data in the scout report "completion" line (--> status 10), and this well tests entry will often have water production when the "completion" scout entry doesn't. Then there are also DT-1 entries showing various things, including water at a later date. So, this particular well seems to have started "wetter" than on average (at 1680 BWD it came in wetter than all but one of 30 encana wells I looked at - the most recent completions, but 5 of the 30 were initially producing > 1000 BWD, so point taken that these things throw the frac fluid back at you - not a surprise). Then, looking at the DT-1 entry, we are down to 134 BWD a month later - still wettish, but okay I gather. I have also noted that a lot of these wells, including this one, essentially never really produce at a rate higher than about half the IP, undoubtedly a methodology issue, and a further argument for carefully monitoring the entire first months production (or even better, some significant # of days at a better defined, but later point in the production cycle, to allow for anomalies caused by blowing water back up the pipe and various other things settling out - this stuff framed on the 1st of the month sort of makes the production data a lot less comparable). But I am wandering off into a whole new problem area - decline curve analysis. Like so many things in life, we really end up not being able to predict things all that well...
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