we are in two producing units - one is 320 acre unit and the other is in a 333 acre unit; both with COP.  Both have one producing well.  Question  what would be a guess as to more wells being drilled. One is producing about 20k barrels and the other about 15 k barrels per month. How many wells can legally be drilled on each unit?  Thanks

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RRC well spacing rules vary by field and depth.
Without knowing which wells are being discussed, it's not possible to give an accurate answer.


Thanks for all the replies to the ? concerning well spacing.  The APIs of the two units are: 255-33256 and 255-32956.

Yes, there are legalities involved with how close they can drill to other wells and unit lines but it also depends on the shape of the units, whether they are shaped such that they are conducive to multiple lateral placement. Also, any answer I or anyone on here gives is pure speculation. Nobody knows. Even the operator won't know for several years. Without knowing anything more, likely, two or more in each unit. Maybe several more. But again, it depends not only on shape but performance of the existing wells and engineers/geologists interpretation of drainage patterns and EUR. There is not a simple answer, sorry.

please give the well api's if you want a decent 'guestimates' - but no-one but a 'lawyer' with access to all documents will be able to give you a 'legal' opinion.

Production-potential wise, there 'could' reasonably be as many as 8 wells +/- drilled on each unit IF all the stars align etc and based on 'current' knowledge; assuming the above is in the middle of eagle-ford - but NOT based on JUST first-month production alone which you posted.

For example, if those wells produce 80K+ barrels the first 6 months, then you can reasonably expect additional wells will probably follow soon (as they payout quick 4 prod co), but still no real known timeline.

On the other hand, if those wells drop to 3k/mo after 6 mos (with less than 60k for 1st 6 mos), then you might expect infill drilling might take decades, as the wells 'just barely' pay out.

Your area could also be riddled with fault-lines that they barely circumvented to get just the 1 well in, meaning maybe zero more.

Kinda hard to guess with almost zero info.  

As the other posters are indicating, there are multiple variables tied to infill drilling and how many wells per unit will eventually be drilled.

Aside from reservoir variability, economics / well performance / production decline / O&G pricing and a company's interval financial / business plan are major controlling factors.

Once the unit is drilled and producing, the operator is in "good shape" and not forced to spend more capital to maintain the lease / unit via new drilling (i.e. unit is HBP)..

Many people want to project new wells and related cash flow into future royalty and related financial planning. If you want to do this, the variables that need to be consider will give you a very wide range of results.

In echoing others, knowing the location / API numbers of your wells would be a great help in allowing posters to give you a more educated opinion of future drilling density

I'm actually wondering this myself. Marathon completed a well I have interest in a couple of years ago and other surrounding units have been in-filled or have permits already filed for in-filling. The API # is 255-32248. The first six months the one well produced 81,181 BBLs. Directly to its south, the Challenger Unit B has like 11 wells already on it. Directly North-East of it, Mohr-Hons has also recently had permits filed for in-filling. I'm wondering if the production is just not good enough to warrant more wells on the unit? 

looks like your one well 255-32248  has produced over 190k bbls! which is awesome production- congratulations -; unit looks like it will support several more wells easily (barring any faulting) based on shape/size/alignment;  probably just a matter of time, as Marathon can only drill so many so fast. Your right in the middle of a sweet spot, so again, congratulations.  Looks like Marathon has been doing 'walking rig' drilling in the area, so takes a bit longer to plan, but then they knock them out quick.

It's a great question to ask, and the rhyme and reason of some deicsions is puzzling to me.  EOG, clearly the dominant operator in the play in Gonzales brought on the Ploeger 1H API 177-33102 on 12-11-13 with an IP of 1,847 bbls and in it's first six months of production has produced 82,000 barrels.  The offsetting EOG - Beall 1H API 177-33119 brought in a little bit earlier on 11-20-13 with an IP of 2,807 bbls has done 154,000 barrels in six months.  With all this hand wringing over payouts, one would speculate that EOG would, in the immediate term permit and drill more wells on the Beall right ? they even have more time experience on the Beall by two weeks. Well instead EOG permitted two on the Ploeger in May 2014, and have just drilled the 2H (177-33377) and 3H (177-33378).  The Ploeger rig came down this past friday.  To date, with the highly productive Beall blowing and going, EOG has not permitted any new wells on the Beall, and the Beall is a very large unit, 859 acres and if you look at the plat for the Beall it's obvious they can stack many horizontals side by side of the Beall 1H.  I should also mention both of these wells are in what has historically been considered the skinny part of the shale in Gonzales.  I think there is something the oil companies are not telling us in regards to what defines a payout on a well, given the logic of permitting and drilling the half producing Ploeger for more wells before the Beall

so my question is, why start infilling a unit where the first well has done half the production of the offsetting lease that has done twice as much ?


This game isn't all about just drilling (and infill drilling) the best areas first.  There are many other factors to consider.  One of the more major ones is the lease terms on each lease.  The terms on the Ploeger Lease might have a continuous drilling obligation where EOG must continue to drill out the lease, or loose the undrilled acreage.  And maybe the Beall, while highly productive, doesn't have as stringent of terms.  Just a thought.  

Tea, that is a good thought, but I have seen the leases for both and they appear to be the same.  With my limited resoning, I have wondered if EOG has done this on the Ploeger to see if they can pull a higher number based on the data from the offsetting Beall.

Texas Tea ! here is a 2018 update to our 4 year old post.  I think there is some clarity now about what is happening  with the Beall unit south of Gonzales in the tiny town of Hamon, TX   The short of the long of it, EOG is combining the Beall and the Barre units to create a supersized unit called the Sequoia, which now has 4 new Eagleford permitted wells.....177-33935, 177-33936, 177-33937, 177-33938  that run under portions of the Beall and the Barre.  See the permit and looks at the plats if of interest.  Of note, is that the completion depths of these new permits for the Sequoia show to be about a thousand  feet below the initial permits for the Beall.  I don't know if this is an example of EOG stacking horizontals or not.  Something is brewing down there though as the 2 existing producing Beall wells have done 630,000 barrels total in 49 months of production dating back to December 2013.

Don't be surprised if the "completion depths" for the new wells are actually the MD (Measured Depth) of the lateral and not the TVD (actual vertical depth) of the targeted formation (i.e. the original formations).

No reason for EOG to be targeting formations thousands of feet below the present producing horizon,


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