Replies to This Discussion

Permalink Reply by Rock Man on May 6, 2018 at 15:02

Joe

You have been very negative about EOG using water and proppant fracs in Louisiana. Even though this is a PROVEN approach in the AC Hz Frac play in Texas (as per the PDF I posted a few days ago), you say you can't do that and expect an AC well to produce in LA.

How is the AC in LA different from that in Texas where this is working? Previously I believe that it was you who had commented that the AC was more like gypsum in Louisiana - that is definitely not the case. I have looked at numerous logs from both areas and see similar open hole log characteristics in the AC between the two states.

The big open hole log variable is the quality of the matrix reservoir - which is one of the key factors for this new play.  

I will venture to say that Blackbrush, MRO and others will be using the same water based proppant fracs on their AC horizontals in Louisiana. This is what has worked for them too in Texas.

All the operators (including EOG) are using some HCL (acid) up front in their stimulations in Texas. And I bet the same lead in Acid volumes were used in the Avoyelles Parish well.

The key here is to break up the matrix reservoir - pumping high volumes of fluid (water) with massive proppant volumes (e.g. 2000 pounds per foot of treated lateral) is the best way to do this in a general sense.

As I have stated many times, the NEW AC play is geared not to chase natural fractures but to fracture stimulate the matrix reservoir. Natural fractures are NOT the key to this new play. 

I am very curious to hear what the differences are between Texas and Louisiana as you see it that makes this approach a non viable option for Louisiana.

Thanks ahead of time for your comments and some good facts to support the differences that you propose are in place between these two areas. I am eager to learn more and open to get some new info if you have it to share.

Permalink Reply by Joe Aldridge on May 6, 2018 at 22:22

According to the completion report we got earlier there was no HCL used.

Permalink Reply by Skip Peel - Mineral Consultant on May 7, 2018 at 1:21

I don't recall that completion report, Joe.  If it is the one from the state it is useless regarding frac additives.  As the form states, the detailed ingredient list is in the FracFocus database.  Here is a cut and paste from the FracFocus Chemical Disclosure Registry.

17-009-20656-00-00

8/27/2017

9/11/2017

Louisiana

Avoyelles

EOG Resources, Inc.

EAGLES RANCH #14H-1

 

Crystalline Silica                                            14808-60-7   100.00000   12.19896

Hydrotreated light petroleum distillate               64742-47-8   30.00000      0.02278

Hydrochloric Acid                                        7647-01-0       7.50000      0.01845

Ammonium Chloride                                      12125-02-9   10.00000       0.00116

Ethanol                                                            64-17-5

Crystalline silica, quartz                                 14808-60-7

Phosphoric acid                                              7664-38-2

Diammonium phosphate                                 7783-28-0

Polylactide resin                                            9051-89-2

Hydrotreated light petroleum distillate              64742-47-8

Ammonium chloride                                       12125-02-9

Organic phosphonate Proprietary

Hydrochloric acid                                           7647-01-0

Acrylamide acrylate copolymer Proprietary

Methanol 67-56-1

Permalink Reply by Rock Man on May 7, 2018 at 4:58

Thanks Skip. As is the case in the Texas AC fracs, I am thinking that this small acid volume is associated with an initial "acid pump in" that is intended to clean up perf tunnels prior to starting to pump frac fluid and proppants.

Permalink Reply by Skip Peel - Mineral Consultant on May 7, 2018 at 5:08

You're welcome, RM.  For the curious, the frac mixture in the Eagles Ranch 14H completion in % By Mass is 87.46758 water and 12.19896 proppant (sand) equal to 99.667% of total volume.

Permalink Reply by Rock Man on May 7, 2018 at 5:18

Thanks - with the conversions I have built into my completion matrix, this works out to slightly over 11 million pounds of proppant.

Comparable in size (per treated foot) Texas AC Hz Frac jobs

I attached the Frac Focus PDF for the Eagles Ranch well (below)

www.fracfocus.org 

17-009-20656-00-00-10182017%2012848%20PM-2193-EOG%20Resources%20Inc...

Permalink Reply by Skip Peel - Mineral Consultant on May 6, 2018 at 13:03

250 MBO Estimated Ultimate Recovery (EUR).  At a $12 million per each well cost, the EUR would need to be somewhere in the vicinity of 600 MBO to make the play economic at current crude prices.

Permalink Reply by Dion Warr, CPL on May 7, 2018 at 8:37

Skip:

Could be a bit lower dependent upon conditions.  77-80% NRI, sustained index pricing ~$65, discounting...  could be as low as 450kbbl EUR.  Also, caveat on pilot hole and logging costs to AFE incorporated into the instant well cost.  If repeatable, the lower number is likely acceptable for IRR.  Keep in mind though that EOG is invested in a plethora of different plays and drilling programs, and comparatively these numbers would not fare well in comparison to those.  600kbbl EUR would be "worth their while" to pursue on Tier 1 / Tier 2 basis.

Based upon the call, we're still dealing with science wells / full-scale AFE drilling and production testing.

Certainly, the higher the EUR, the better.  250kbbl over a program is not going to fit the bill for anyone, even if all other costs are ideal (which it doesn't appear that this was the case here, either).

Permalink Reply by Skip Peel - Mineral Consultant on May 7, 2018 at 9:15

Yeah, maybe.  I think I'm safe with the 600 MBO number for now.  Let me know when we get to 450. :-)

Permalink Reply by Rock Man on May 7, 2018 at 10:35

Good points about NRI and its impact (but expect NRI's to decrease as new mineral owners hold out for 25% royalties). Operating costs as to SWD (need SWD wells), transportation, lack of pipelines / marketing costs, etc. all play into the bottom line here.

But I personally believe that one of the biggest issues tied to economics is production decline and profile. If you get an Eagle Ford type decline profile where there is a rapid production drop after the first year and then a flay line equal to about 95% of the initial production rate in Year #5 or #6, you will get a very different IRR versus a well that has a much lower production decline that doesn't achieve the "flat line / low rate" point until year #10 to #15.

So lower EUR's will have better IRR in the latter case.

Key to this decline rate is tied to reservoir properties (e.g. matrix perm) as well as GOR, pressure decline in the reservoir and how operators opt to produce these wells (gas lift, jet pump, ESP's, beam pump, etc.).

This will be an interesting play to watch - just like watching the Eagle Ford, various areas in the Permian Basin, The C in Tx, Haynesville, Utica, etc.

Same evolution - just different formation names and areas!

Permalink Reply by Rock Man on May 6, 2018 at 14:50

Let me clarify this comment that Bob Z posted

================================================================================== 

He posted:
One a different thread, let me what reiterate Rock Man said awhile back: Where there are no natural fractures in the AC there are no hydrocarbons of any consequence.

==================================================================================

I did not say that - my point in the AC is that there are TWO plays - the old, historical natural fracture play that has been chased for decades where operators depend on mother nature to create natural fractures and then operators produce the O&G from those fractures.

The "NEW" play is what EOG and others are chasing, i.e. the NON natural fracture play where the O&G is contained in the reservoir in matrix porosity (pores). Operator needs to frac these reservoirs to liberate and produce the O&G.

I did say that there are areas where there is little to no matrix porosity. In these cases, there is next to nothing to be able to produce.

I hope that clears up my comments on what the play concept his as to the AC Hz Frac play

Permalink Reply by Rock Man on May 6, 2018 at 14:45

Just sat down and read over the long list of comments as follow up on the EOG AC well and play in Louisiana.

Agree that 250,000 BO EUR (250 MBO) is far from being economic if well costs are in the $12 MM range.

Is that what the EOG well in Avoyelles Parish cost in total? First time I have seen that number associated with that well. That is a VERY high well cost - normal laterals for an AC Hz frac well should be in the $6 to $7 MM D&C (drilled and completed) range. And 250 MBO would not work for that well cost either.

Let me make one point - I have a hard time knowing of any play where the first well in the trend was the type well for success in that play. Eagle Ford, Permian Basin, Marcellus, Utica, Haynesville, Fayetteville, the AC Hz Frac play in Texas - all the initial wells are "not the best" or even the "norm". There is a learning curve - EOG condemning the AC Hz Frac play in Louisiana after one well is highly unlikely.

Way too early on the learning curve to make those sort of decisions.

• ‹ Previous
• 1
• …
• 33
• 34
• 35
• 36
• 37
• …
• 59
• Next ›
• Page