Anyone local to the Avoyelles area hearing anything about the Eagles Ranch Well? It appears that they recently finished drilling well and should be moving frac crews on location soon.

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Thanks. Curious why you didn't include all 18 data points? You show it through Jul 2018 but data is there through Feb 2019?

Also, you said "the % number (e.g. 6%) is the present oil rate versus the original max rate."

I don't understand the quoted statement. "Present oil rate" means what? Feb declined 4.2 BOPD. How did you get 6%?

I am erasing my previous decline curve post and attachment since I totally screwed it up / that is what I get for rushing to get something posted! LOL

Thanks for bringing this to my attention.

Attached graph shows all the data from the production months thru Jan 2019. Note the decline number for Jan 2019 is 2.3%.

This and other numbers / percentages for each month are the percentage of that month's rate vs the initial max rate (2016 BOPD based on production test). I am using 30.4 days per month in my BOPD calculations (easier to do this).

So with Jan 2019 rate of 46.5 BOPD, this is only 2.3% of the max rate of 2016 BOPD.(if I use 28 days, the percentage will be 2.5%).

This is a much steeper decline that what one would see in other unconventional reservoir production profiles. But with this well being a "toe down" lateral which is still flowing on its own with no artificial lift, one needs to wonder what would happen if EOG were to install some sort of lift to unload the lateral and get the fluid off the perforations.

Attachments:

Looks like SONRIS updated the Gas Production numbers.

LEASE\UNIT\WELL PRODUCTION

RPT DATE LUW CODE STORAGE FAC DOC USE WELL CNT OPENING STK OIL PROD(BBL) GAS PROD(MCF) DISPOSITION CLOSING STK PARISH
02/01/2019 052025 1 510 1414 3696 1591 333 AVOYELLES
01/01/2019 052025 1 267 1696 1823 1453 510 AVOYELLES
12/01/2018 052025 1 414 2123 1769 2270 267 AVOYELLES
11/01/2018 052025 1 702 2161 1734 2449 414 AVOYELLES
10/01/2018 052025 1 319 2507 2107 2124 702 AVOYELLES
09/01/2018 052025 1 470 2728 2523 2879 319 AVOYELLES
08/01/2018 052025 1 277 3413 3355 3220 470 AVOYELLES
07/01/2018 052025 1 332 3612 3490 3667 277 AVOYELLES
06/01/2018 052025 1 612 3783 3569 4063 332 AVOYELLES
05/01/2018 052025 1 350 4792 4760 4530 612 AVOYELLES
04/01/2018 052025 1 477 5291 4906 5418 350 AVOYELLES
03/01/2018 052025 1 488 6374 5741 6385 477 AVOYELLES
02/01/2018 052025 1 548 7382 6916 7442 488 AVOYELLES
01/01/2018 052025 1 177 8801 8334 8430 548 AVOYELLES
12/01/2017 052025 1 378 11171 10765 11372 177 AVOYELLES
11/01/2017 052025 1 622 14192 15394 14436 378 AVOYELLES
10/01/2017 052025 1 453 27609 29029 27440 622 AVOYELLES
09/01/2017 052025 1 0 26896 24024 26443 453 AVOYELLES

If that gas volume is correct, that is a massive change in GOR from the previous trend - basically around 1000:1 to over 2600:1. It will be interesting to see future months to see if this trend continues.

Or I wonder if EOG has done something to the wellbore that is impacting production? 

April 23 2019 production test shows test rate of 56 BO, 72 MCF and 249 BW on a 64/64" choke with 138# tubing pressure. Slight drop in oil cut (22.5%) from previous test (25%) - appears that well has settled into to a consistent albeit less than sterling "groove".

But remember that this still a toe down well that doesn't appear to have any artificial lift installed to unload the wellbore.

Using DrillingInfo.com EUR calculator, this is a 316 MBO and 321 MMCF well (projection out to 2069). Point forward economics tied to both product costs and operating costs (plus mechanical integrity of the lateral wellbore over time)

Attachments:

LEASE\UNIT\WELL PRODUCTION

RPT DATE LUW CODE STORAGE FAC DOC USE WELL CNT OPENING STK OIL PROD(BBL) GAS PROD(MCF) DISPOSITION CLOSING STK PARISH
03/01/2019 052025 1 333 1612 2035 1427 518 AVOYELLES
02/01/2019 052025 1 510 1414 3696 1591 333 AVOYELLES
01/01/2019 052025 1 267 1696 1823 1453 510 AVOYELLES
12/01/2018 052025 1 414 2123 1769 2270 267 AVOYELLES
11/01/2018 052025 1 702 2161 1734 2449 414 AVOYELLES
10/01/2018 052025 1 319 2507 2107 2124 702 AVOYELLES
09/01/2018 052025 1 470 2728 2523 2879 319 AVOYELLES
08/01/2018 052025 1 277 3413 3355 3220 470 AVOYELLES
07/01/2018 052025 1 332 3612 3490 3667 277 AVOYELLES
06/01/2018 052025 1 612 3783 3569 4063 332 AVOYELLES
05/01/2018 052025 1 350 4792 4760 4530 612 AVOYELLES
04/01/2018 052025 1 477 5291 4906 5418 350 AVOYELLES
03/01/2018 052025 1 488 6374 5741 6385 477 AVOYELLES
02/01/2018 052025 1 548 7382 6916 7442 488 AVOYELLES
01/01/2018 052025 1 177 8801 8334 8430 548 AVOYELLES
12/01/2017 052025 1 378 11171 10765 11372 177 AVOYELLES
11/01/2017 052025 1 622 14192 15394 14436 378 AVOYELLES
10/01/2017 052025 1 453 27609 29029 27440 622 AVOYELLES
09/01/2017 052025 1 0 26896 24024 26443 453 AVOYELLES

Interesting to see GOR variance over the past few months - well was running around 800:1 GOR before jumping up to 1075 and then 2614:1 (Feb 2019) GOR. And then back to 1262:1.

Oil rate pretty consistent when you look at the per day rate (49 to 56 BPD).

Keeping in mind that this well is a toe down lateral that is still producing under its own power (i.e. no artificial lift), one has to wonder if these recent variances are the result of the well / lateral "burping: more gas from some of the perforations over time and the well bore continues to unload and stabilize

By the latter point, remember that the lateral is a long series of perforations that will respond to a frac differently due to variable reservoir parameters - including pressure and the intensity of the frac job associated with any perforation cluster. This causes the lateral to produce fluids (O&G and water) like a pulsing hose instead of there being equal flow across the entire length of the lateral

It certainly is interesting, but my question is can a company the scale of EOG have a field of these wells (with the same decline rate) pay for the cost of the well fast enough to satisfy investors and then pay for the overhead to keep them going once they plateau ?

I do realize that longer laterals will increase production, but the decline rate should be the same none the less.

EOG or anyone else could not economically survive with wells like this one. But I believe that EOG is looking at this as a "test well" to monitor AC reservoir performance in this area. Which may explain the apparent lack of artificial lift installation.

Or they have opted to not spend any more $$$ on this well.

Remember that this was the FIRST AC Hz Frac well in this part of the trend (Louisiana). I will tell you that the first wells in most hz frac plays are far from being "average" (and on the poorer side of economics). Just the nature of the Hz D&C beast!

Key to improvements?

Longer laterals, toe up vs toe down, landing zone selection and keeping laterals in zone, optimum cement jobs, improved frac approaches (perf cluster spacing, proppant volumes and types, fluid types and concentrations, diverter usage, etc.).

And of course apply all these variables to the heterogeneity of the AC reservoir across the area.

Decline rates will vary based on all the aforementioned factors.

Thanks Rock Man for your observations and comments.

I think $100 per barrel of crude would be the most helpful.

Higher prices always help - but my experience is that they tend to come with higher operating costs (D&C). But overall a good thing for sure.

In today's climate, it is hard to figure on anything as to O&G prices over time. Stability would be nice

I don't recall but did they drill this well underbalanced or did they drill them conventionally as Anadarko did a few years back?

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