[ROCKMAN]

Still a good bit of life left out in the Gulf. But note the time lag. No estimate of first production but at least a couple of more years is an easy guess. So a good ten years from discovery to first bbl of oil.

Discovered in 2005 the Stones Field is located in the Gulf of Mexico on Walker Ridge Block 508. In a water depth of 9,576’, the field is situated 200 miles off the Louisiana coast. The rig drilled the Stones-2 to a true vertical depth of 28,560’. The discovery encountered several hydrocarbon-bearing sands in the Lower Tertiary interval. Then in 2008 another well reached a depth of 29,400’ and confirmed the previous discovery of multiple oil-bearing sands.

The Stones Field development will start with two subsea production wells tied back to the FPSO vessel (floating, production, storage and offloading unit) followed later by six additional production wells. This will be the greatest water depth any FPSO has been deployed anywhere in the world. This first phase of development is expected to have annual peak production of 50,000 boe/d from more than 250 million boe of recoverable resources. The Stones field has significant upside potential and is estimated to contain more than 2 billion boe of oil in place, according to Shell. Technip reported Friday that it has been awarded a contract by Shell Offshore Inc. to lay THE WORLD’S DEEPEST GAS PIPELINE at the Stones field.

I would take that 2 billion bbl upside with a big grain of salt. At 30% recovery that would be 600 million bo. At 50k boepd it would take over 30 years to produce. If there is that much oil it will obviously take a much larger development plan to get it out. And that could mean another 10+ years. Great if all that oil is really there but it will be a long time coming out of the ground.

[rollin]

Rockman
So with 20 discoveries like this we could let the Bakken fizzle out (as it will anyway).
When they say recoverable oil, is that technically recoverable or economically recoverable?
Seems like a huge depth to go, almost 4 miles in ground. What's the crust depth in that region?
Any estimates on the cost of this operation?

[ROCKMAN]

rollin – being a public company Shell is going to be very careful with their press releases. I can promise you a half dozen of their lawyers who understand the SEC regs very well review every press release. So any reserve number that they release would be economically recoverable at today’s prices. But they can get tricky when they say things like “upside potential” etc. In such cases they aren’t saying any portion of that number is proven. That’s why I said one should be cautious about swallowing that 2 billion bbl number.

That’s the typical depth for production in that trend: 25,000’ to 34,000’. If nothing goes wrong such a completed well can run $60-$100 million. Have some trouble and it can run over $150 million. Last dry hole I was on out there cost $148 million and killed all the potential on that lease block. The production facilities can easily run several hundred $million and over $1/2 billion at times. Given the water depth and the drilling depths I would guess they’ll spend well over $500 million by the time they’re done. And that doesn’t include probably $10 of millions spent on the from end for seismic and leases. But then think about that 250 million bbl estimate. That would mean it cost them only a few $’s per bbl to develop the field. But the full economic analysis never looks that good. The time value of money and the long lag time to not only have production begin but to also deplete the field greatly reduces the rate of return. Think of paying interest on a $500 million loan for 5 to 7 years before you get your first $ of revenue. And while you’re producing all those years your monthly operating expense might run into the $millions. Also notice Shell uses the "boe" card: barrels of oil equivalent". This can be very misleading. They take the amount of NG the field will produce and generate a $value and then divide it by the price of oil to come up with a equivalent volume of oil. In theory one could take a field with 100% NG and no oil and represent it as having X boe reserves. Shell should make a nice profit on this project but it won’t be nearly as much as the average person might think.

But offsetting a Bakken fall off? Will take 10 years for this one field to add 50,000 boe per day. There aren’t 20 such fields under development right now AFAIK. Too few oranges to offset the loss of all those apples if and when it happens IMHO.

[rollin]

Thanks for taking the time to give me a very detailed set of answers.

One thing that puzzles me though is the geothermal effect at those depths should produce a lot of gas vs. oil. Is there something else going on in the Gulf that makes it possible for oil to stay intact at those depths?

[ROCKMAN]

rollin - That was the pleasant surprise when they started drilling out there. The temperature gradient in the Gulf Coast varies greatly from area to area. To some degree that gradient is dependent upon the rate of deposition of the sediments. The heat generated in the mantel does make it to the shallow sediments but very slowly. The Deep Water tertiary sediments are RELATIVELY young and haven’t been subjected to the same heat gain. There are wells in S. Texas that reach 400+ degrees in just 16,000’. There are wells in the DW GOM that don't approach those temps at even 35,000’.

So you’re correct: there is a temperature window that oil becomes unstable and breaks down. But those DW fields, despite those depths, are still not that hot.

Here’s more info then you’ll ever want to know. http://www.searchanddiscovery.com/docum ... 13forrest/

[dcoyne78]

Rockman,

Great info as usual.

This oil is great, but it may not be enough to offset declines from existing fields. You said there are not 20 fields in the Gulf in development, do you have a rough guess about how many fields are being developed? Maybe 5 to 10? Is the field discussed above fairly "large" or is it more in the "average" range for GOM deep water projects.

My understanding is that the prospective production must reach some minimum level before the project makes economic sense at current price levels.

On the boe question, are these done on an energy equivalent basis (6000 cu ft nat gas = 1 barrel of oil) so 6 BCuFt Nat gas = 1 MMbo? Or is it based on the current economic value of the output per MMBtu which is roughly 5 MMBtu of nat gas sells for the same amount as 1 MMBtu of crude (assuming $100/barrel of crude and $3.50/ MMBtu Nat Gas?

DC

[ROCKMAN]

DC - The best I could find was initial production dates. For 2011: 11 fields, 2012: 7 fields, 2013 far: 2 fields. Go to the BOEM website and you can find a very long list of all the DW fields. A lot more developed fields out there than most would guess.

Seems like the common range is 100 to 500 million bbls. Expensive neighborhood to play and can take 10 years to get on production but no where else to find such large individual fields. And on a per bbl cost to develop much more profitable than the shales. But these are large structures and their numbers are vey small compared to the number of shale wells left to drill. Just my WAG but I would say just 10 to 15 more years of big discoveries out there.

[ROCKMAN]

BOE: based on what ever method you choose to use. That's why it's important to know what the source used. Most common is 1 bbl = 6 mcf. Obviously doesn't come close to a monetary equivalent given that 1 bbl of oil is selling for the price of 25 or so mcf.

[curlyq3]

Hello Rockman ... just wanted to say that I followed you over here to Peak Oil from TOD ... your knowledge and style of delivery is effective for alot of us "Outside The OIl Patch People" ... I spend a bunch of my time trying to spread some info regarding the Nulear disasters that are developing in our world ... I have learned a great deal from you "hands on guys" about the problems we face with fossil fuels ... Thank You ! ... curlyq3

[dcoyne78]

$this->bbcode_second_pass_quote('ROCKMAN', 'B')OE: based on what ever method you choose to use. That's why it's important to know what the source used. Most common is 1 bbl = 6 mcf. Obviously doesn't come close to a monetary equivalent given that 1 bbl of oil is selling for the price of 25 or so mcf.

[dcoyne78]

$this->bbcode_second_pass_quote('ROCKMAN', 'B')OE: based on what ever method you choose to use. That's why it's important to know what the source used. Most common is 1 bbl = 6 mcf. Obviously doesn't come close to a monetary equivalent given that 1 bbl of oil is selling for the price of 25 or so mcf.

[ROCKMAN]

DC - Yep...the typical conversion used is 1:6. And there's the potential confusion. So 6 million mcf = 1 million bo. At $3.50 per mcf the NG would be worth $21 million. And 1 million bo at $90/bbl would be worth $90 million. Thus the logical conclusion: $21 million = $90 million. So if I say I have 50 million boe in reserves what are my reserves worth if 95% of my reserves are oil? If it's 55%? Here's a hint: the typical convention is if you have more than 50% of the company value as oil you report boe. If the majority is NG you report mcfe. But I don't think that's law.

Yes: booked proved reserves have to be indexed to the price of oil and NG. If prices drop then booked proven reserves will typically be reduced in volume as well as value.

[rockdoc123]

$this->bbcode_second_pass_quote('', 'h')e use of BOE to report reserves seems like a bit of a smoke screen. At one time Natural gas and oil were fairly close on a $/BTU basis, but when a BOE of natural gas is worth one fifth of a BOE of crude, it seems that it is no longer even apples to oranges, more like apples to watermelons.

[dcoyne78]

$this->bbcode_second_pass_quote('', 't')hird party reserve audits/evaluations conducted by the likes of DeGolyer MacNaughton, Ryder Scott, Sproule, Gaffney Cline etc usually report both barrels of liquids and Mcf of gas. They also roll it up as a single number BOE. This is pretty consistent across the group so it is pretty easy to see what reserves and types of reserves a company has by simply looking at their 10K (US) or 51-101 (CAN). These reserve reports tend also to calculate out NPV10 for 1P and 2P using a price model usually based on current prices escalated at inflation.

Most corporate presentations will replicate these numbers (anything contradictory is illegal) in a manner that is often more easy to digest.

[rockdoc123]

Is NPV10 a 10 year NPV or is the 10 the annual discount rate, what discount is typically used (if 10 is for years)?

Its simply the NPV through the life of the reserves calculated at a 10% discount rate. In actuality the reserve reports issued often quote 10, 15 and 20% discount rates.

I'm always cautious about what liquids are lumped together. If the product in question can be used to offset actual C5+ use then I think it should be included. So if, for example, fuel use is being offset by propane it makes some sense to include that in the liquids tally IMHO

[Subjectivist]

$this->bbcode_second_pass_quote('ROCKMAN', 'D')C - The best I could find was initial production dates. For 2011: 11 fields, 2012: 7 fields, 2013 far: 2 fields. Go to the BOEM website and you can find a very long list of all the DW fields. A lot more developed fields out there than most would guess.

Seems like the common range is 100 to 500 million bbls. Expensive neighborhood to play and can take 10 years to get on production but no where else to find such large individual fields. And on a per bbl cost to develop much more profitable than the shales. But these are large structures and their numbers are vey small compared to the number of shale wells left to drill. Just my WAG but I would say just 10 to 15 more years of big discoveries out there.

[ROCKMAN]

Sub - Nope. For the most part the DW players and the shale players exist in two very different universes. Very little overlap. And the DW players are almost completely internally funded by their own cash reserves and credit lines. Chevron et al don't use investor $'s. In fact, lately it's been more common for Big Oil to be buying their own stock instead of selling. As far as shale players go I don't have a hard numbers but I doubt much of the capes is coming from private investors. Might be a lot of citizens investing in the stocks of those pubcos but that's not money available for ops other than what might be raised in IPO's. Again don't have numbers but I would guess just a relatively small amount of capes from that source.

The biggest capex problem is probably diminished credit lines of the shale pubcos. For instance Chesapeake has probably sold almost $30 billion in assets and they were still around $10 billion short on their budget needs. As far as DW GOM the current projection is for an all time record of rigs drilling. At $700,000 to $1 million per day per rig it wouldn't seem like there's much of a capes for those companies.

[ROCKMAN]

The question came the other day after the announcement of the latest DW GOM discovery: how many new fields in the future. I don't know but here is the count for the number of fields that began producing during the last 10 years:

2002 - 13
2003 - 8
2004 - 13
2005 - 7
2006 - 15
2007 - 7
2008 - 5
2009 - 8
2010 - 4
2011 - 3
2012 - 6

Not absolute but looks like the rate is dropping. The question was if we could expect 20 new fields coming to production in the next 12 months. Doesn't look likely. OTOH there are many undrilled leases and currently over 1,800 approved drill permits. But it cuts both ways: while the learning curve goes up there are fewer fields to discover. And, though not perfect, companies try to drill the best looking prospects first. But also know it's not uncommon to permit more wells than one eventually drills. It can take a couple of years to get a permit so you apply for every possibility.

But we should still have a lot of oil developed out there for at least the next 10 -15 years IMHO.

[dcoyne78]

$this->bbcode_second_pass_quote('rockdoc123', 'I')s NPV10 a 10 year NPV or is the 10 the annual discount rate, what discount is typically used (if 10 is for years)?

Its simply the NPV through the life of the reserves calculated at a 10% discount rate. In actuality the reserve reports issued often quote 10, 15 and 20% discount rates.

I'm always cautious about what liquids are lumped together. If the product in question can be used to offset actual C5+ use then I think it should be included. So if, for example, fuel use is being offset by propane it makes some sense to include that in the liquids tally IMHO

[dcoyne78]

Note that more than 1/3 of NGL output in the US is ethane (37 %) (not used at all in refining or blending), another third is propane. Maybe propane should be included, we could throw in Natural Gas as well as that offsets fuel use for heating.

It makes more sense to separate these fuels into gases and liquids, only C5 and C5+ should be included as liquids IMO.

DC