Replies to This Discussion

Permalink Reply by Ryan Howrish on November 18, 2024 at 11:32

My thoughts are that if 330' stages efficiently drained that area with large fracs, stages would not be spaced 120-140ft apart.  One of the significant step changes in productivity from the first several years of development to today is the reduction in stage and cluster spacing. We spent a ton of money in the Marcellus, Eagle Ford, Austin Chalk, and Haynesville trying to understand the impact different completion designs had on productivity.  I think the reason lots of old wells with 300-400ft stage spacing are identified as re-frac candidates is because the fluid and proppant loading was too light and the stage and cluster spaicng was too wide.  I think very little gas is efficiently drained much beyond the last perf cluster at the hell and toe of wells.

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Permalink Reply by Skip Peel - Mineral Consultant on November 18, 2024 at 11:39

I took a stab at the proppant loading in early HA wells in my 2022 NARO-LA presentation.

https://gohaynesvilleshale.com/forum/topics/my-naro-presentation-re...

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Permalink Reply by Ryan Howrish on November 18, 2024 at 11:49

Early wells were dramatically understimulated. We actually found that fluid loading was a more statistically significant variable on the productivity of wells. Some early wells had 15 bbl/ft and I’ve been involved with the testing up to 130 bbl/ft.

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Permalink Reply by Skip Peel - Mineral Consultant on November 18, 2024 at 12:03

Early HA well spacing was for 660' offset between wells assuming a recovery factor of ~12.5% per well (8 laterals per section).  It appears that the early frac designs may have had recoveries as low as ~5%.  That left a lot of un-stimulated gas in place (GIP).  An opportunity for operators to experiment with re-fracs.

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Permalink Reply by Ryan Howrish on November 18, 2024 at 12:57

You will never achieve 100% recovery ultra-low permeability reservoirs.  40% is maybe on the low side, but 100% is not achievable.

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Permalink Reply by Skip Peel - Mineral Consultant on November 18, 2024 at 13:02

Then published ultimate recovery estimates have been far off reality.

Permalink Reply by full name on November 18, 2024 at 13:30

  It looks like the new wells are fracturing past the 300 foot boundary for each section.  I have one old well that went from 2,000/mo to 70,000/mo when the section adjacent to the well was fracked and another well saw a substantial increase when the section at the head end was fracked.

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Permalink Reply by Skip Peel - Mineral Consultant on November 18, 2024 at 13:37

That is not an isolated instance. The industry has astutely avoided the fact that frac cylinders occasionally reach further than planned.  This was demonstrated conclusively with the fracks that communicated across multiple DeSoto sections and caused a number of older wells and water wells associated with those wells to blow out.  The Office of Conservation issued several emergency orders and eventually the wells were plugged.  The question that remained was one of formation damage and the ability of additional HA wells to be drilled in those sections.  There was litigation over the damage.

https://www.dnr.louisiana.gov/assets/OC/EMER18-003/20180907_EMER18-...

https://www.dnr.louisiana.gov/page/emer18-003-desoto#orders

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Permalink Reply by Rock Man on November 18, 2024 at 18:07

In my opinion, these long distance "frac hits" are tied to having frac jobs intersect natural fracture systems - and then those "open conduits" transporting that frac event / associated fluids and proppant long distances away from the primary lateral wellbore.

This is a different issue than that of frac hits between parent and child wells when the frac stimulation is associated with a reservoir that hasn't been complicated by natural fractures.

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Permalink Reply by Skip Peel - Mineral Consultant on November 19, 2024 at 2:02

I agree, Rock Man.  The 2018 Emergency Declaration covers a very large area over the southern half of Township 13N-15W - Sections 21, 22, 23, 26, 27, 28, 33, 34 and 35.  This is not normal communication between adjacent wells.  The question I have is whether the horizontal operators in that portion of 13N-15W were aware of the subsurface fracture network.  I looked at this in 2018 for attorneys representing the mineral owners in those impacted sections.  I'm unsure where that litigation is in the courts. 

Only three wells have been drilled into the affected area since 2018.  As existing wells deplete, it will be interesting to see if HA operators avoid this area.

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Permalink Reply by Ryan Howrish on November 19, 2024 at 3:03

I read through the emergency order and all of the associated supplemental documents. If I read it correctly, the emergency was created because gas was detected in an aquifer.  After all the data was submitted and reviewed, the last supplement reduced the AOI to the South 1/2 of 22-13N-15W and the entirety of 27-13N-15W. A much smaller area than originally designated. Without seeing all of the technical data, it seems like the issue was possibly a combination of stimulating a Haynesville or several Haynesville wells and activating a pathway to a vertical well that may not have had proper isolation. Is gas migration a widespread issue across the Haynesville play, or is it limited to this emergency order? Unlike areas of the Marcellus where I worked, I don't recall gas migration being a significant issue when working the basin.

Gas migration can be a large and serious problem, but it is a different topic than zone-to-zone frac hits, which I believe was the original topic in this thread.

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Permalink Reply by Skip Peel - Mineral Consultant on November 19, 2024 at 3:25

A number of wells across the impacted sections blew out and had sustained periods of eruptions.  These were older vertical completions and water wells drilled in conjunction with those earlier wells.  That was the original reason for the emergency order.  Follow up testing revealed the gas in the aquifer.  There has been little to no testing for natural gas in aquifers that serve private and public wells.  Only in a handful of cases has some event resulted in testing.  I recall a handful that were connected to Haynesville depth wells.  When this was in the news and under discussion, I explained that naturally occurring natural gas exists in many shallow aquifers and that the only way to determine if the natural gas was from a deep well or from the shallow natural sources was to test for contaminants in addition to methane.  Where that testing was performed, the majority of tests revealed that the gas did not originate from the deep formations being drilled.  Considerably earlier we went through a prolonged discussion about many claims of natural gas in potable aquifers that resulted from Josh Fox's documentary Gasland which was upsetting to many people and eventually largely debunked.  We had a lot of short term members who were spreading those misconceptions.

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