ROCKMAN wrote:baha - 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.
pstarr wrote:MD wrote:The 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?
The declining flow rate results in a colder flow, and so paraffin wax (found in petroleum) builds up inside the pipe . . . constricting flow even more. Cooler pipe. That's one of those unfortunate/nasty positive feedback loops.
Normally they'd run a scaper pig down the pipe. But not with think rusty walls??????
sarc on Since economics trumps geology (and demand creates supply) they will just have to helicopter the oil out. One barrel at a time. Who ever said peak oil impacts flow rate? sarc off
rockdoc123 wrote: 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.
Actually no, Rock. I don't think so. I happen to know that Shell had a rather large internal staff working the Chukchi and Beaufort plays. Very little of that work was done by consultants. And you are going to need a bigger checkbook too. At the time they pulled out, Shell had sunk about 5 Billion $$$ into their Alaska exploration project.ROCKMAN wrote:pstarr - "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.
Alaska_geo wrote: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.
Indeed it has been in service much longer than was anticipated. And, certainly some day TAPS will no longer be viable. But we ain't there yet. I've been hearing people claim that TAPS was in imminent danger of shutting down since the '90s.MD wrote: 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 wrote:Conoco's onshore discovery looks to be a lot more likely to actually put oil in the pipeline than Caelus' Smith Bay play.
Therein lies the crux of the matter. Caelus has made some very big claims. These are based on big assumptions and extrapolations, from very skimpy and/or questionable hard data.Plantagenet wrote: If everything Caelus's says about the discovery pans out then it is so big that it will eventually be developed as well
Alaska_geo wrote:Caelus has made some very big claims. These are based on .... questionable hard data.
Alaska_geo wrote:However, based on what they have shown and the data they claim to have, there are lots of reasons to question if this is a viable discovery.....
My $0.02 worth.
Plantagenet wrote:
Smith River is the largest oil discovery in Alaska in four decades.
vtsnowedin wrote:Plantagenet wrote:
Smith River is the largest oil discovery in Alaska in four decades.
2.4 billion barrels at 19 mbpd USA consumption works out to a four month supply for the USA.
MD wrote:vtsnowedin wrote:Plantagenet wrote:
Smith River is the largest oil discovery in Alaska in four decades.
2.4 billion barrels at 19 mbpd USA consumption works out to a four month supply for the USA.
That's silly and meaningless math. Stated over and over here for years in varying context. What counts is the flow rate over time, and how it impacts the viability of the pipeline over years.
vtsnowedin wrote: 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.
I didn't say they don't have a discovery, or that can't be as big as they say. In fact, I said that I hope they are successful. I am saying that based on the data they've shown so far, there are lots of reasons to be cautious. First and foremost, they have projected production of 200,000 bbl/day without having run a single well test.Plantagenet wrote:Alaska_geo wrote:Caelus has made some very big claims. These are based on .... questionable hard data.
What part of their data do you think is "questionable"? What part of their data are you disputing?
Here's what Caelus has released so far: With an estimated 6-10 billion barrels of oil in place, Smith Bay ranks as one of the world’s largest oil discoveries in recent years, and the largest on Alaska’s North Slope in four decades......
The estimates are based on the two wells drilled last winter and existing 126 square miles of 3D seismic. Exploratory well Caelus-Tulimaniq #1 (CT-1) and step-out Caelus-Tulimaniq #2 (CT-2) targeted a large Brookian submarine fan complex in Smith Bay, spanning more than 300 square miles along the North Slope region. The fan was successfully drilled and logged in both wells, encountering an extension of the accumulation 5.25 miles northwest of the CT-1 discovery at the CT-2 location. Gross hydrocarbon columns in excess of 1,000 feet were encountered in each well, with CT-1 and CT-2 logging 183 and 223 feet of net pay respectively.
Extensive sidewall coring and subsequent lab analyses confirm the presence of reservoir-quality sandstones containing light oil ranging from 40-45° API gravity.
Plantagenet wrote:So what are your reasons for doubting its a viable discovery?
Its not like Caelus is a "fly-by-night" operation. They are a highly successful independent oil company with a good track record on the North Slope. They discovered the nearby Ooguruk field and they are producing it right now.
Plantagenet wrote:
And they have announced more work at Smith Bay. According to their website Caelus is currently planning an appraisal program, which includes drilling an additional appraisal well and acquiring new 3D seismic survey over outboard acreage. This is exactly what they should be doing to delineate this new discovery.
I don't get what part of this is "questionable". Do you think they shouldn't have announced their discovery at all?
You seem to be implying that Caelus is running some kind of scam --- Like they are trying to sucker in some oil major to the Smith River play based on giving out "questionable" data. But I assure you people in the oil majors are far too smart for that. They aren't going to invest billions in a new project without have a very full and complete understanding of what they are buying into. So that isn't what is going on here.
Plantagenet wrote:
IMHO what Caelus is trying to do is make their case for the money promised to them by the state of Alaska. If you are an Alaskan, then you probably know that the current tax code here allows oil companies to claim tax credits if they do new exploratory work in Alaska. Well---thats just what Caelus has done, but the state hasn't paid them they money it owes them. What better way for Caelus to make its case for getting the money its owed by the State of Alaska then to announce this new and potentially large discovery on the north slope. The oil tax credits were designed to encourage new exploration on the North Slope to find new oil. Well, Caelus has done exactly what the State of Alaska wanted when it set it up its tax system for oil companies.
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