I would like to know if anyone in the Frio, Lasalle or Atascosa county area has had any of their wells completed or is Venado only drilling wells. The RRC completion site doesn't show any wells completed. When we went to their BBQ and they bragged how much better they were at completing wells than Cabot, I am sure that we were all excited but the proof is in the pudding! If anyone has any info as to a completion by Venado it would be greatly appreciated. I'm not looking for specifics just your opinion of how the well came in.

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Venado is filing completion reports but it is taking them FOREVER to file the final reports with IP test information - they usually file two "pre IP" W2 reports initially and then the actual IP report months later (this keeps the Tx RRC satisfied as to filing requirements).

They followed a similar filing process and time frame in their Eagle Ford efforts in Lee County around Giddings a few years ago.

Anyway, attached are two completion reports with IP info - Bluejack and Kothman. One can argue about how good the IP test numbers are vs Cabot and others, but the proof is in the pudding (i.e. Production).

I have attached the Bluejack production curve - 142 MBO in 10 months or 473 BOPD average (not bad for low 30's API heavier oil). This well's production was very low in latest reporting month - this could be due to mechanical issues and/or switching to artificial lift.

The Willow lateral produced 102 MBO in a similar period.

I haven't compared these directly to Cabot or other operators' results and performance, but it is apparent that Venado is hitting this area very hard - they have a total of 10 wells (including Bluejack, Willow and Kothman) "frac'd and completed" - but only two with actual IP reports.

All this info is on the Tx RRC site.


Thanks Mark, I have been looking for info on RRC site but haven't seen this yet. I guess I am just getting ahead of myself and need to be more patient! I just get mad that they haven't been taking care of the wells that we have ( workover rig cleaning out the wells that Cabot completed right before they sold) When I ask them if they are going to do anything to improve the production I am told that they do not have plans to do anything until production reaches 0!! Cabot cleaned out the wells about 1 year after completion and it drastically improved production! Frustrated!!

Patience and frustration - two of the prime emotions normally seen in the oil field. On both all sides of the equation (operator to landowner / royalty owner).

Sounds like you are seeing a good example of capital maintenance by Venado - they don't see any sense in spending discretionary funds on producing wells that are already keeping their acreage HBP. Their purchase of these properties initially needs to be supported by pouring as much capital as possible into new wells to increase cash flow and "prove up" their acquisition to their investors.

My question - when will they be looking to divest these assets? That is almost definitely in their game plan so that they and their investors can get a big pay day.

I have to figure that these assets will be sold 3-4-5- times or more in their lifetimes.

Key points to look at in these completions are:

  • Treated lateral length
  • Amount of oil produced prior to IP test rate
  • Flowing or Pumping on IP test
  • Rates (obviously)
  • Oil % cut of total fluid (oil plus water)
  • Oil gravity

Among other things.

These two wells are different in many ways based on the W2 forms. Two different lateral lengths, one flowing and one pumping, different IP rates, very different amount of oil produced prior to IP test rate being calculated, different oil gravities (3-4 API degrees is a big difference with respect to oil viscosity and ability to move from reservoir into lateral).

As always, time will tell how good the Venado wells will be.

I have to figure that they are looking closely at adjustments to target / landing zones as well as frac stimulation specifics (e.g. perf cluster locations and density, proppant loads, diverter usage, fluid volumes, etc.) plus production approach (flowing vs ESP's, etc.)

Thank you all for putting this information out there. Venado is actively trying to acquire a lease from me and any information to any landowners about completion strategies I would like to inquire on further details. The Kothmann Bluejack and Willow wells are all of interest to me. Also, Percheron, Appaloosa DUC wells waiting to be completed by operator. I believe my lease has similar rock characteristics, with probable reserves in place.

I am new to the group but am happy to see there are others with interest in the area.

Have you looked on TX RRC site for completion info? That is best source and the one I would use. The Venado website may say something about completion strategy but I highly doubt it.
Yes I have been looking at the RRC for info. Grayleaf is also a nice well by Cabot. Is the lateral portion longer allowing for more stages to complete in sweet spot? How does the lower gravity oil (30-35) help with production and refining? Is this more valuable to oil?

Nicholas, Welcome to the best group on the web!! Shortly after Venado bought Cabot's leases, they invited all the land and royalty owners to a BBQ and presentation that was well attended! They introduced themselves and put on a slide show explaining their difference in drilling and fracking. I and many of the owners that I knew left very impressed. Their fracking approach was what really impressed me. Shorter but more stages and tighter frac shot that produced more web like fracking than what Cabot did on our first wells.So far we have not had any new wells drilled by Venado so I can't speak to how good they are yet but hope we get a well from them soon so I can compare the two companies! By the way, their are some very knowledgeable people in this group like Mark that are willing to share their experience with us so feel free to post any question you have! Good luck and I hope Venado pays you a fair price for your lease!!

Thanks for comments yesterday by J Crawford.

As for completion info, there is a lot of info to look at as one attempts to get a handle on just how good any particular well is as well as comparing well results.

Remember that a completion report is a "point in time" - the most important info for any well is its production history and decline over time.

Some the key factors to look at as to a completion report are the IP test info (oil, water, gas). Is well pumping or flowing during test? How much oil is reported to have been produced prior to test rate being recorded? (if minimal oil produced prior to test, it is very early in the post frac flowback and the O&G numbers will not be representative of the true rate for that well. During post frac flowback, the initial max volume of fluid will be frac fluid /. water. One has to wait until the initial flush of water dies down to see the "true" O&G rate).

Once you get past the IP info, one should be looking at the length of the treated lateral (i.e. first perf to last perf). Ideally, the longer the lateral, the better the well will be over time since more section is being opened up and frac'd. But the lateral has to in the "sweet spot" to optimize the well results (and there is no way for the casual observer to know if this is the case or not).

The frac approach (proppant and fluid volumes, perf cluster locations, pumping pressures, etc) is also ultra important. But info like per cluster density and locations plus pumping pressures, diverter usage and other details are not made public. The proppant and fluid totals are available - but if there are posted only in Frac Focus, one needs to create a set of conversion formulas to convert the Frac Focus percentage numbers to pounds of proppant and gallons of fluid.

Lastly, a comment on oil gravity. The Cabot / Venado area has historically had low API oil gravities in the Eagle Ford - ranging from 28 / 29 to low 30's. The lower the API gravity, the more viscous and thick the oil is. And more difficult it is for that oil to move from the reservoir rock into the fracture volume that is created. API vs viscosity relationships are not one to one - a move from 33 to 32 API is not a simple one to one increase in oil thickness / it is more extreme as to this factor. One can look up viscosity changes vs Oil gravity to see these changes.

A parallel factor that impact IP results (and moving oil out of the reservoir into the fracture system) is gas presence - or GOR (gas to oil ratio). The lower the GOR, the less energy there is in the formation to help the oil move out of the rock. The Cabot / Venado area has historically been a low GOR area in the Eagle Ford - so IP rates tend to be lower as well as EUR's being lower than areas with higher GOR and higher API oils.

In summary, analyzing IP / completion reports is a bit like "CSI: Oil Field" as to what one can extract from the information that is provided.

Hope this helps a bit as to this issue of interest.



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