[rockdoc123]

For the companies in question given they would be able to recover all exploration and development costs from the State in exchange for ~18% royalties I think it would still be an economically decent project. The field had a reasonable GOR so my guess is the gas lift comes from re-injection of produced and separated gas.
Just looking at the production from 2005 through 2011 (all I could find from the Alaska gov't) the NPV10 (using WTI pricing at the time) would be in the order of $3.6 billion gross or ~$3.2 billion net. Of course this assumes all costs are recoverable (I can't remember what the exact deal was with similar concessions but I seemed to remember this was the case).
Production from 2006 onwards gradually decreased and in 2014 BP sold off the majority of it's interests in Northstar and a couple of other fields to Hilcorp (which at the time was a Houston based company concentrating in Lousiana E&P). The press from BP stated that for smaller fields like the ones they farmed down to Hilcorp it made more sense to be in the hands of a small company who could get more out of the field whereas BP was concentrating on their bigger fields elsewhere.

[JimBof]

$this->bbcode_second_pass_quote('ROCKMAN', 'b')aha - That's why I'll tease an explorationist (if I think he can take) as to why he includes an economic analysis of his wildcat prospect: in the ernture history of the oil patch no one has ever submitted an economic analysis of an exploration project that didn't look viable.

Which is why I never look at those numbers. As your mother understood each project is given a probability of success. That times the reserves target yields the RRE...Risked Reserve Economics. Every exploration hand knows what the RRE has to look like for management to buy the idea. Even for relatively dumb managers you can't put a Ps of 80% on a risky project. But you can push the limits on reservoir size. After all if the target hasn't been drilled you don't know how big it is.

Thus comes the wonderful world of Excel spreadsheets: one can vary the Ps with reserve size using limits that are defendable. With just a few clicks the exploration hand can find that sweet spot of the reasonable risk (and a tad optimism is allowed because he knows something others have missed) and reasonable target size.

What I'll dig deepest into is target size. More then a few times I've seen targets that would represent the top 5% percentile of what has been discovered in a trend that has been explored for decades. That way even using a low Ps the RRE don't look too bad. And yes: a few times I've seen target numbers larger the anything ever discovered in the trend.

Most understand what I've described by the kind phrase: reverse engineering. Less kind: f*cking made up numbers. LOL. And if you notice a touch of bitterness in my tone there's a good reason: I've functioned as a development/reservoir geologist most of my career. You outsiders should understand that exploration hands will be forgiven for a number of dry holes. But development wells are expected to always work.

My first project at Mobil Oil in 1975: exploration drilled two wells that found a variety of different pay sands in a field with numerous fault blocks. Using seismic data projected those reserves to all those untested fault blocks. And not overly optimistic Ps...20% to 35%. Being a new development geologist fresh out of school all I did was push the paper work thru, give target coordinates to the drilling engineer and go log the wells. Wells drilled from the platform set over the site of one of the two discovery wells which had been plugged and abandoned. So started out with risked reserves of 20 million bbls and 100 bcf. And then my first 5 "very low risk" development wells were DRY HOLES. For instance the well the platform was set over found a 120' thick NG reservoir which was projected to exist in numerous offset fault blocks. Not only did that sand not contain NG in it in those fault blocks we never even saw the sand again.

So reserves went from 20 million bbls to 1 million and 100 bcf to 20. And only because we found a small fault block at the edge of the lease that the operator of that offset lease discovered. Our exploration department didn't even project reserves there originally.

And yes: I was nicknamed the "undevelopment geologist". LOL. Funny now...not then.

And that really isn't a condemnation of explorationists...without their efforts there would be no need for development geologists. LOL. But just some insight to just how difficult the process is. And that there was never been any f*cking "easy oil". If that field were analyzed today we would know what is and isn't there...seismic data has improved greatly from 40+ years ago. It is much easier to identify viable prospects today then ever before. If there is ever a time of "easy" oil/NG then it's today. The success rate today is much higher then it was decades ago...that's not the problem today. The problem is the limited number of conventional prospects left to find. IOW lots of conventional prospects decades ago that were difficult to find vs few conventional prospects today which are relatively easy to find.

[Alaska_geo]

$this->bbcode_second_pass_quote('pstarr', '')$this->bbcode_second_pass_quote('MD', 'T')he elephant: That pipeline is approaching "paper thin" status along much of its length. Between that and declining flow rates, I am surprised it hasn't been shut down yet. How much of what flows down that pipe is now just hot water?

[Alaska_geo]

$this->bbcode_second_pass_quote('rockdoc123', ' ')Production from 2006 onwards gradually decreased and in 2014 BP sold off the majority of it's interests in Northstar and a couple of other fields to Hilcorp (which at the time was a Houston based company concentrating in Lousiana E&P). The press from BP stated that for smaller fields like the ones they farmed down to Hilcorp it made more sense to be in the hands of a small company who could get more out of the field whereas BP was concentrating on their bigger fields elsewhere.

[Alaska_geo]

$this->bbcode_second_pass_quote('ROCKMAN', 'p')starr - "have just compared never-before-attempted off-shore oil production in the stormy frigid arctic ocean with . . . Mom and Pops'" Believe it not you and I could partner up and drill some wildcats in the offshore Arctic. All it would take is a big fat check book.

With financial support I can put together a geologic, geophysical and engineering with as much (and probably more) experience then Shell Oil had working on its well. Except for upper management the vast majority of the hands doing the actual physical ops are consultants and third party contractors.
-----------snip----------------
There have been a number of small operators that have taken concessions in the Deep Water off west Africa and found nice oil fields.

So are you ready, partner? Let me know when you get that $100 million raised and I'll start pulling the bodies together.

[MD]

$this->bbcode_second_pass_quote('Alaska_geo', '
')Lot of BS going down here.

And note that while there is some wall loss in spots due to corrosion, TAPS is no where near "paper thin".

The oil companies continue to propagandize that the minimum feasible flow for TAPS is around 300,000 bbl/day. (This is the company party line, to argue against state production taxes.) However, some years back some internal BP documents emerged during a court case regarding taxes. These documents showed that BP's own internal estimate of minimum flow for TAPS was around 100,000 bbl/day. They showed in fact that BP has been booking reserves under the assumption that TAPS could operated down to that lower rate.

It should be noted that the 100,000 bbl/day rate was assuming that modifications were made to TAPS, principally adding heat at strategic locations. The economic feasibility of that obviously depends on oil prices. My understanding is that some, but not all, of that work has been done.

[ROCKMAN]

Geo - "...I don't think so. I happen to know that Shell had a rather large internal staff working the Chukchi and Beaufort plays." Go back up the thread: the conversation was primarily about the ability of small companies to handle field operations. You spent a lot of times on rigs: how many times when the operating company had 50% or more on the rig manned by employees? Let's ramp that way back: on a rig with 150 souls on board how often have you seen 15 (10%) of them being company employees?

Last time I was on a Deep Water GOM rig drilling a 34,000' well in 5,000' of water the operator had 4 employees onboard. Sometimes...at other times just 2. And their primary duties was monitoring the work of the consultants (like me) and the service company personnel. Yes: lots of company employees back in Houston reading the morning reports with great interest. But not one was involved in actually getting the well down. I have no doubt if you were a member of a 10 employee independent you would have no problem getting an offshore well drilled in your backyard. You probably have a go-to-list of the consultants and service companies you would use.

As well as the ones you wouldn't let walk your dog let alone drill your well. LOL.

[Alaska_geo]

$this->bbcode_second_pass_quote('MD', ' ')By "paper thin" (in quotes, you'll note), I meant that it's been in service longer than it's initial book. That said, I understand capital infrastructure can be in service far past it's design, which sometimes is set more for depreciation purposes than actual viability. What will, and will continue to happen, is maintenance costs will continue to rise every year. Added heat zones to accommodate reduced flow? Sure, technically feasible, but that's a major project itself. 100,000 a day? Sounds like a pipe dream to me, but what the hell, I'm just an amateur.

[Alaska_geo]

Rock-
I think we are talking about two different issues. Indeed, there usually aren't a lot of company people on a rig in Alaska, as elsewhere. I was talking about staff to actually figure out the geology and come up with a viable prospect.

My point was that true offshore exploration in the Chukchi and Beaufort (as opposed to shallow water nearshore like Smith Bay) is ungodly expensive. My earlier post was in error. I believe I said Shell spent 5 billion dollars in their Alaskan offshore adventure. Actually, it was more like $7,000,000,000. With one dry hole to show for it. Conoco and Statoil were also both pursuing their own plays in the Chukchi. Both also bailed out.

Nearshore shallow water stuff like Smith Bay is a lot cheaper, but still a very spendy deal. Definitely not a play for mom and pop oil companies. One of the reasons that Caelus is putting so much hype on some pretty sketchy data is that they are in way over their heads, and desperately want a partner with deep pockets to bail them out. At this point, Conoco's onshore discovery looks to be a lot more likely to actually put oil in the pipeline than Caelus' Smith Bay play.

[Plantagenet]

$this->bbcode_second_pass_quote('Alaska_geo', 'C')onoco's onshore discovery looks to be a lot more likely to actually put oil in the pipeline than Caelus' Smith Bay play.

[ROCKMAN]

Geo - Yes, that was exactly my point. The post I was responding to was that a small operator couldn't handle drilling operations because they didn't have a big staff like a Shell Oil be it a shallow bay or open Arctic waters.

Don't be modest: I have no doubt you could put together a team redrill the Shell well. And probably do a better job of it. I was surprised by the unanticipated problems Shell had. From my experience Shell was near the top of my list of companies that over-engineer such projects with a lot of safety redundancy. Did it surprise you?

[Alaska_geo]

$this->bbcode_second_pass_quote('Plantagenet', ' ') If everything Caelus's says about the discovery pans out then it is so big that it will eventually be developed as well

[Plantagenet]

$this->bbcode_second_pass_quote('Alaska_geo', 'C')aelus has made some very big claims. These are based on .... questionable hard data.

[rockdoc123]

my own view on this is it is very interesting but until such time as they have tested a well it is speculation. I can't count how many tmes over the years I was involved in oil "discoveries" that showed oil saturation on wireline logs, sidewall or even full diameter cores that showed extensive oil staining and live oil in pore space but when subjected to Drill stem test including extensive long term swabbing, clean up acid and in a few cases a clean up frac......result was no flow.
It would be interesting to see the full analysis of the wells (i.e. porosity, permeability etc). Some of the Brookian turbidites I've seen were very fine grained and had permeabilities on the low side. That may not be the case here but it would be surprising to see the full stack of turbidites all being in the more "reservoir quality" facies.
I would leave it at saying....early days, more work needs to be done before getting too excited. Could be huge, too early to tell.
Note that they are a private company. A publicly traded company would have had to be more careful with their press release.

[vtsnowedin]

$this->bbcode_second_pass_quote('Plantagenet', '
')
Smith River is the largest oil discovery in Alaska in four decades.

[MD]

$this->bbcode_second_pass_quote('vtsnowedin', '')$this->bbcode_second_pass_quote('Plantagenet', '
')
Smith River is the largest oil discovery in Alaska in four decades.

[vtsnowedin]

$this->bbcode_second_pass_quote('MD', '')$this->bbcode_second_pass_quote('vtsnowedin', '')$this->bbcode_second_pass_quote('Plantagenet', '
')
Smith River is the largest oil discovery in Alaska in four decades.

[Plantagenet]

$this->bbcode_second_pass_quote('vtsnowedin', ' ')That 2.4 billion barrels if produced at an average rate of 400,000 bpd would keep the TAPS going for another 16 years or so all on it's own and much longer if brought on line at a rate that balances the decline of other North slope fields.

[Alaska_geo]

$this->bbcode_second_pass_quote('Plantagenet', ' ') $this->bbcode_second_pass_quote('Alaska_geo', 'C')aelus has made some very big claims. These are based on .... questionable hard data.