RRC production data - how many wells in a "lease"?

[Roy]

How is it possible to compare individual well production using TRRC monthly production data, when operators routinely consolidate multiple wells in RRC lease data? Do the monthly production drop-downs have some well-number code I’m missing? How do experts compare wells if public database commingles multiple wells into single leases?

Example. Cimarex (nka Coterra) operates ten Dixieland 55-6 wells, seven disclose production but three say “No Report”. These ten wells have ten different coded leases. If three wells’ production is combined, whey would not those three “No Report” wells share a lease number with a multi-well lease. API 389-38681 (lease 289675) reports big production, is it reporting multiple wells? Similarly, 389 38682 (lease 289676) is “No Report”, which of the ten different leases captures that well’s production?

[TennisDaze]

Six digit RRC Lease numbers are for gas wells and there is only one well per lease number. Combined wells are limited to 5-digit oil lease numbers. The production volumes for each 6-digit gas lease is limited to a single well. The No Report wells are not producing - could be shut-in due to problems or perhaps never fraced.

[Roy]

Thanks much. Are there exceptions to the rule?

Both 389 38663 (lease 290115) and 389 38673 (290158) are designated gas wells, yet they share a drop down permit window, and single production drop down. TRRC told me in an email that lease 290158 is reported under 290115. By coincidence, both wells are practically on top of each other (areal) although TVD depths differ by 456’. RRC’s explanation seems to contradict the “gas well single lease reporting” principle.

Surely, these two laterals do not share a single vertical shaft, like branches on a tree? Such technology is not practiced, right?

[NMoilboy]

The wellheads are 20’ apart. Two different wells with very similar planar drill paths. 2H in the Wolfcamp A, 3H in the Wolfcamp B (or lower A depending on semantics). Drilling wells on top of each other with only 400’ vertical separation in this day and age seems suboptimal (vs staggering them) but they were fracked at the same time and it’s not obviously affecting anything

There aren’t a lot of successful examples of two fracked laterals from a single vertical shaft. I can’t speak to the TRRC stuff. But mostly you are banging out a poop-ton of cash per acre on those Dixieland wells.

[Roy]

Thanks, I’ve learned more from you than TRRC. Wish there was a good book on tight O&G and lateral shale wells.

This Dixieland 55-6 (Reeves Cty) development is puzzling, CEO referred to it as triple stacked in an earnings call last year, I understand him to mean three levels of wells normally W-shaped lattice. What’s odd is the big picture on this 12-well development. 3 of 12 wells are shut-in or DUC, stranded investment?

3 “shalllow” wells (Wolfcamp A), but one is shut in. This WCA tier is most volume.
3 mezzanine wells (upper Wolfcamp B?), second best volume, none shut in.
4 deep (lower Wolfcamp B) wells, 2 of 4 shut in.

[NMoilboy]

Are there 12 wells? This is what I had (cartoon below). All the Red ones are producing (and a tiny amount from the old Dixieland 10 well), or at least had allocated well volumes in April 2022 (see table below). Only place it is “triple stacked” is sort of on the east flank. I believe the 5H was junked while running casing, could be wrong, but never produced and listed as abandoned.

The TRRC as a data source strinks relative to other states. You sort of have to give them a pass as its a zillion wells, but it’s a disaster.

[Roy]

Where did you source your data table, especially your production data and last date April-2022? The RRC website shows “No Report” for monthly data, for two wells 3H and 9H in the drop-down panel on their GIS map. You have data for these two wells.

Blows my mind that 5H may have been aborted before frack, guessing $5 million spent in drilling phase. I see the G-1 completion for 5H calls it “shut in producer”. The W1 well status code reads “Z unperfed completion”.

Probably the reason the CEO called this development “triple stacked” is of the eight new wells, 3 average 219’ below top of formation, 3 others average 455’ below top, and 3 average 660’ below top.

BTW, I don’t have royalties in this development, trying to understand it inasmuch as we own in an undeveloped section 3-4 miles south, this approach is likely what same operator may follow in our section.

[NMoilboy]

That table is from IHS/Enerdeq. They just take the lease volume and allocate %s based on the respective last test for the wells reported as “active”. May or may not be correct, but it’s the best guess.

Oh, ha. No interest in that unit. Ooops. Yeah probably will do same a few miles south. But…maybe they won’t. I know the feeling.

w.r.t. 5H, in my experience 1-2% of wells end up junked. Takes a big issue obv. You screw up the liner/prod casing and can’t fish it and then you are hosed. Or sometimes you frack and part the casing. Etc. Only answer is to start over again. Just drilling a well to TD should cost $3m or so. Says the guy out of the oil well business for 4 years.

[AJ11]

I think the technology to drill multi-lateral wells may be well established: https://www.drillingmanual.com/multilateral-wells-drilling-technology-full-guide/

[Roy]

Thanks, I see there are several YouTube videos about multilateral drilling, I just don’t hear about it being used on land.

[tracy_lenz]

Multilateral wells tend to be reserved for areas where the surface location is especially difficult or expensive, like protected lands or offshore. It is well established as a practice (since it’s been around a while for conventional reservoirs) but also expensive and risky. I personally only know of a couple multilateral wells onshore, and it was more a 2006-2009 way to test theories and reservoirs with limited capital.

I also agree; about 1-3% of the wells we drilled (when I was with an operator drilling horizontals) ended up junked somehow. Sometimes we would try completing the well anyway, but usually once a junked well, always a junked well. But maybe other companies have better “remedial engineers” (possibly my favorite title I’ve seen) than my company did .

[NMoilboy]

Drilling them is not that hard. We did them in CBM, offshore UAE, etc. A long time ago. For onshore US shale, convincing yourself to spend $5m to attempt to pump 25m# of sand down a maybe isolated second lateral (and all the shenanigans associated with that) versus just drilling another vertical hole is where, in my opinion/experience, the math works against multilaterals. The few that I saw in unconventional fields were a mess and a product of somebody in research deciding that they knew more about operations and risk analysis than people who had been to an oilfield. Your mileage may vary.

[AJ11]

I was looking at a GIS type map once and saw a multi-lateral well and wondered the same as you. With some more research, I found mention of multi-lateral wells in Austin and Washington counties.

Multilaterals Provide An Unconventional Approach To Shale Reservoirs

A pilot project in a major shale play represents one of the first attempts to measure how multilateral wells could deliver cost efficiencies in unconventional fields.

" Takeaways This multilateral technology project proved that, even in unconventional fields, it is possible to reenter existing wells to add laterals that will increase reserves while also minimizing investment. The operator of this pilot well was able to drill two laterals to TD from the same wellhead, reduce the number of trips necessary to access each lateral during the stimulation phase, complete multistage hydraulic fracture stimulation of each lateral while maintaining hydraulic isolation across the multilateral junction and test each lateral before commingling production from both laterals through the same wellhead. The success of this unconventional pilot well illustrated that on multiwellhead pads, multilateral technology can drive cost-saving efficiencies on every step of the process, from zipper fracturing operations to CT and workover interventions."

[Roy]

Recap. Thx for educational thread. Big picture: I was puzzled by no production from 3 of 8 new wells … 2 of them are child wells, 1 evidently failed during drilling.

This development Dixieland State 55-6 by Cimarex (nka Coterra) 1280 acres Reeves County … 2-mile laterals, all categorized as gas wells (for tax benefit). Operator had 3 old wells, applied for 8 new wells Nov-2019. Covid pandemic exploded 3/2020. 1 of the 8 new wells evidently failed (5H, API 389 38675) in Feb-2020 as shut-in producer, w1 code Z “unperfed completion”. Commenters opine 1%-3% of laterals fail. The other 7 new wells commenced production Nov-2020.

CEO lauded Dixieland as improved productivity, fewer wells produce same as past tighter spacing, called it a “triple stack” (Earnings call transcript 8/5/21). PowerPoint slide describes “Dixieland 7-well project, spacing implies 9 wells/section”, superior production per foot than legacy 12-14 wells/section. No mention in earnings call that 5H apparently failed, or if Dixieland was intended to be an 8-well project. You wonder if operator will return to drill the aborted 5H path, because 5H leaves a void in the lucrative 10,600’ Wolfcamp A sweet spot.

“Triple stacked” = new wells 220’, 450’, 650’ below top of Wolfcamp 10,419’.

General rule: gas wells report production individually on separate leases, not combined. However, 2H is parent to 3H child, 8H is parent to 9H child, so 3H & 9H do not report production on TRRC GIS drop-down panel. The parent/child wells are vertically separated by 450’. TRRC emailed me 2-3H & 8-9H “are part of a stacked lateral set. All production are filed to the ‘reporting’ wellbore. The production on the child wells are reported to and combine with the parent well’s production.”

Parent/child wells do report separate production on the state Comptroller CONG website.

Not sure how to identify or link parent-child relationships. RRC drop down panel for child well 9H (API38938682) completion: type well “Not eligible for allowable”.

Spacing continues to evolve. Possibly, onshore multilateral well drilling may be deployed more in the future, especially when Permian tier-1 acreage is depleted. Multilaterals, laterals sharing a common vertical shaft like tree branches, are established technology, but uncommon onshore. Dixieland is not multilateral wellbores.