I took a close look at the Altamont Bluebell well stats recently.
Some of what I have noticed is very interesting. Taking all the stats and excluding only wells in the database which were never successfully drilled and are identified as (LA - location abandoned), the mean production is about 336,000 barrels of oil per well and about 570,000 mcf of gas. If wells that had a very poor initial production are excluded that produced less than 40,000 barrels of oil (these usually have IPs lower than 200 boe/d most lower than 50 boe/d), then the mean oil production goes up to over 420,000 barrels of oil and 600,000 mcf of gas. The mean production for wells that have an IP typically above 200 boe/d or better therefore comes in at 420,000 barrels of oil and 680,000 mcf - combined that is about 520,000 BOE. Another point is that in the mean production estimate, it includes many wells that are still producing. Many of the best wells continue to produce for 30 years or more. Which means that the mean production estimate underestimates what the mean production will eventually be when the wells are completely depleted.
Something else that is interesting - more wells are being drilled in the Altamont Bluebell field that are in the same 640 acre area that the initial wells were drilled in. I looked at several of the wells that were drilled in the 70s and 80s and compared them to wells drilled in the last 3 years. The more modern wells appear to be better than the initial well and in fact, I'll be surprised if they don't push up the mean well average by 20% or more. This indicates to me that the spacing of 640 acres is not sufficient to drain the oil and gas on the acreage and that new drilling, completion and stimulation methods are better. This has huge implications for the Altamont Bluebell fields because it means that they may be less than 1/2 drained and maybe even less than 1/3 drained of producible oil and gas with current technology.
My last observation is that the geology of the area and thickness especially of the target formations close to the Bar F are more than I would have expected after reading some older papers on the area. It is possible that other operators therefore misjudged the potential of the land position that HNR has in Utah. Chances are that the heart of the Altamont Bluebell area has more oil due to thicker formations. But where HNR has their leases, part of that trend could be just about as productive as the Altamont Bluebell area.
With HNR's 46,000 net acres, assume that 23,000 net acres are in a good productive trend for the Greenriver Wasatch oil. I think at least 4 wells will be needed to efficiently drain the reservoir and maybe that figure will increase to 8 or more. So far, all the wells that HNR has discussed will IMO produce in excess of 500,000 boe. HNR will ask for 640 acre sizing of the blocks but with the ability to drill other wells in the same block. If they drill 4 wells per block, that is 128 net wells on the 23,000 acres. (this is only an estimate for the productive Greenriver Wasatch trend. The area could be larger than 23,000 net acres). The 128 net wells using the 23,000 net acre assumption could produce over 50 million barrels of oil.
I've noticed some of El Paso's recent wells in the Altamont Bluebell area and their results continue to improve. El Paso has indicated that they will reduce drilling costs from $5.2 million to $4 million and the cost of completions from $2.1 million to $1.2 million. El Paso's total cost is therefore about $5.2 million.
HNR has some advantage in that the Greenriver and Wasatch formations that they are drilling is up-dip from the center of the Altamont Bluebell field. The average TD in the Altamont Bluebell area is 14,500 feet according to a study that I read. For HNR, the average TD may be at about 11,000 to 12,000 feet. meaning the wells will be 2,500 to 3,500 feet shallower requiring less drilling time and pipe. The well design might also be "slimmer" which would increase the drilling speed and reduce the cost. Recently, HNR indicated that the completed well including associated infrastructure for the latest well would cost $4.5 million and that they believed they could get this below $4.0 million. This would bring HNR's costs below El Paso's by about $1.2 million which is reasonable given the shallower depths. Additionally, HNR's "lifting costs" will be below El Paso's. Given the up-dip location, the average oil and gas saturation may be higher in the HNR's area although the formation thickness would be expected to be less.
The result of the 5 well program are going to be key for HNR. Five wells are sufficient to begin to get an understanding of the type of results HNR might get from the drilling. If the new wells have the same depletion rate as seen in the Bar F, then they will likely produce over 500,000 boe over the productive lifetime of the wells. The 3rd well of the 5 well program is reported to have higher than expected pressures - this could mean that this well will be much better than the others.