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Ed
excellent document posted, with loads of data to research, thanks
Just had a quick skim read and noticed this page 12:
"At Cole Creek, Cuda’s working interest is 33% with its partner (COPL) owning the remaining
67%. Existing production has already occurred from the Shannon, Dakota, Lakota, and
Frontier zones including secondary recovery in the Dakota. As a result, the shallower
opportunity in the Shannon has been depleted/produced. However, the Cole Creek area
does offer meaningful near-term opportunity especially in the F2 and Dakota zones. Two
horizontal wells were drilled in 2007 and produced from the Dakota and F2, thereby de risking the potential of these zones.
These wells confirmed the productivity of the zone and with the F2 well having a cumulative oil production of 61 MB and the Dakota well having cumulative oil production of 145 MB.
With newer completion techniques and more fracs, these wells could potentially surpass the 1,000 B/d IP-30 type-rates observed at nearby wells. Relative to the Barron Flats Unit, Cole Creek is somewhat shallower at 9,000’ versus BFU at 12,000’. Additionally, the area is more overpressured versus the BFU. The higher pressure could be a positive for initial rates"
some big positives from this, AM strategy understood better:
- Only CUDA is a partner in CC - so could be a more viable full WI buy out just for CC, no Chinese partner negotiations
- Wells expected to be around 1000 bopd and with high pressure so earlier high production rates
- Multiple targets, shallower cheaper drilling than BFU
Tiburn,
Its sure worth keeping an eye on those horizontal wells as you're doing for sure. Also page 3 of the Cormark report on Cuda will raise some eyebrows. A well close to CC field to the North came online at around 1300boepd, also others in the basin have done as high as 4k boepd.
https://542357-1754095-raikfcquaxqncofqfm.stackpathdns.com/wp-content/uploads/2019/04/CUDA_Initiating_Coverage_21012019_CORMARK.pdf
But anything from 400-4k boepd would be great per well as that could be funded from the low risk vertical infill/deve wells drilled into the Upper and Lower Shannon at BFU and CC. This is the significant upside that Art hinted at in the presentation you posted earlier. Roll on the relist as that's when things only start to get interesting.
Regards,
Ed.
yes Tilburn and Ed, looks like Arthur is in his full form!!!
Ed
great post thanks and to all
Im trying to keep tabs on Continental et al drill campaigns, a recent well in Frontier was 375 bopd I understand, pretty good.
If AM tracks their campaigns and reacts to what they find a few miles away , in the exact same reservoir targets and stacked plays, then it de risks his planned 20+ drill campaign to a marked extent - I have a feeling he is going to go as fast as possible on the drilling side, the flooding and BFU production is now in hand and just rolls by Southwestern on a well established approach, leaving COPL tech staff to focus on the exploration with their assist and knowledge - its yet another positive having the same SW tech team onboard.
Tiburn,
Agreed, that's what makes this one so exciting, its what can be done with these assets at low cost. Already we can see the correlation with the 10mmcfd and 1800bopd by July, with rates estimated to go to about 4,000bopd by year end. The increased gas and propane injection results in increased gas production as the chart clearly shows. As the oil is produced there's more void space down there to be filled with gas to maintain and increase the reservoir pressure. Therefore gas rates gradually increase to 23mmcfd or there about from around 16mmcfd re-injection and about 8mmcfd bought. This would need to be maintained imo to keep production at 6,000bopd plateau for multiple years as the production profile shows.
The clear upside is shown by the fact that the oil production from the BFU peaks at around 8000bopd by around the end of next year (not a long way away). Before it settles back to about 6,000bopd. Likewise for CC the gas injection is to cause peak production of 3500bopd, lets guess for now 1 year later say end of 23 as a guess. However we'll have to add to that the as yet unknown potential of the horizontal Dakota and Frontier wells and the significant potential of the deep horizons. So if all stays on the rails we should be looking at 10,000-12,000bopd gross over the next 18-36 months, perhaps higher depending on the horizontal results (some of our neighbours have had impressive flow rates per well). That's what makes the outcome of the NOP very interesting for us.
But the growing production at the current net levels and COPL's substantial cash balance should make the option with Essar on 226 easily affordable. Nigeria could as we know add substantial 2P from Essar's planned 18 wells, we even get a free crack at Noa-2, letting Essar take the risk. So they certainly have a path from current assets (let alone pre-licence spend on additional acquisition) towards mid cap. There is no way that I can see that the NOP can keep up with our pace on the vertical and horizontal drilling plans, so we're gonna have a very very interesting 18 months ahead for sure.
Regards,
Ed.
I'll second that Tiburn. Well done.
Tiburn - as always excellent research and what an asset to this board
Gazza, I take it you’ve not bothered reading the last update when your asking that
what date is relist?
The deal gets better every day. Just give it time to bloom.
Getting ready to buy as the early silly sellers will appear on relist.
C.
Great find - again, Mr Tilburn.
I mentioned a few names on here a few days ago, one name was missing in my mind.
It was you Sir. Your research is legendary!!!
GLA
Nice work Tiburn, another golden nugget that could propel the SP.
Has I said earlier, on re-list, why go chasing rainbows.
edit - $48,000 a day revenue, or $1.44m per month gross.
http://www.canoverseas.com/wp-content/uploads/2021/02/COPL-Atomic-Corporate-Acquisition-Presentation-02-21.pdf
"COPL re-simulated BFU plateau production (January 2021): 7,000 bbl./d at 10 MMCF/d gas injection rate"
So 10 MMCF/d gas total injection rate is required- looking at chart slide 17, this stabilises around 6 MMCF/d bought NGL gas bullets for flood, with the remainder being the reinjected gas produced.
However - the total gas injection rate approaches 23 MMCF/d by 2025.
So either more gas is required for reinjection to keep the 7000 bopd oil production stable, or the surplus gas produced can be sold - the solid red line shows this at 16 MMCF/d by 2025.
So to the deal with Tallgrass Midstream, Noob posted a very useful link previously in which he highlighted the gas pipeline map - connects into COPL
If we assume that surplus gas is sold (as implied by the extents of Tallgrass pipeline to all producers) , then 16 minus 4 reinjected MMCF/d = 12 MMCF/d
https://www.tallgrassenergy.com/Operations_TMID.aspx
"Tallgrass Midstream (TMID) assets are strategically located in Wyoming’s Powder River and Wind River basins. Assets include natural gas gathering facilities and natural gas processing and treating plants. TMID creates value for customers by processing and treating natural gas for flow into interstate pipelines and on to a diverse customer base that includes residential, commercial and industrial users. This allows producers to deliver their product in a market-ready form and to recover natural gas liquids (NGLs) – propane, butane and natural gasoline."
So the model is sell your natural gas and get the flood NGL bullets in return - its that capacity COPL is paying to expand at the Douglas plant - just for COPL.
Slide 18 shows these trucked in NGL bullets arriving at the BFU gas injection site - CC would need a similar site its assumed.
So if COPL are selling the excess gas, 12 MMCF/d at $4 per 1000 is $40,000 a day revenue, or $1.2m per month gross.
https://www.eia.gov/dnav/ng/hist/n3035us3M.htm