[ROCKMAN]

There is no lack of capital to chase DW prospects...those players have the capex What's missing in a number of cases is economic justification. IOW a company can continue some DW projects if they don't anticipate first production in 5 to 10 years. IOW current oil prices aren't a concern in a number of prospects. .OTOOH a company that spent hundred of $millions in the last 6 years on DW projects probably really f*cking upset. LOL.

[hvacman]

$this->bbcode_second_pass_quote('ROCKMAN', 'O')TOOH a company that spent hundred of $millions in the last 6 years on DW projects probably really f*cking upset. LOL.

[ROCKMAN]

Hman - As the home run AND strike out leader, Babe Ruth, can attest. LOL.

[Zarquon]

I found some numbers on new GOM projects, all in deep water:

http://www.eia.gov/todayinenergy/detail.cfm?id=25012

The time between discovery and first production for the eight fields coming online in 2015 was:
11, 6, 6, 6, 5, 3, 3, 2 years

"With the exception of Anadarko's Lucius field, each of the fields was developed as a subsea well that is tied back to nearby existing production facilities. The use of subsea tiebacks allows producers to reduce both project costs and start-up times."

For anticipated production from fields coming online in 2016/17 the times are:
11, 8, 7, 5, 2, 2 years

"Shell's Stones field development uses the first floating production, storage, and offload (FPSO) vessel in the GOM. FPSOs allow the development of fields that are complex, that have unique reservoir properties, and that do not have existing infrastructure."

Time between discovery and begin of the project isn't given, but the estimate of 5-10 years project time seems reasonable - that is, if infrastructure is in place that a field or well can be tied to.

And there were eight fields coming online in 2015, four expected for 2016 and apparently only two in 2017. That says nothing about the reserves or expected production level, though. It would be interesting to see how many projects were canceled since 2014.

[ROCKMAN]

Z - Good numbers...thanks. But note most of those quick tie backs are not new MAJOR field discoveries. Typically they are smaller reserves to far to reach with directional drilling. Same dynamics we saw on the shallower shelf for more than 30 years:a big field is discovered and developed over many years. Then a single small platform (a "caisson well") is drilled near by and tied back.

But here's the tricky part of that stat: if it took 6 years to develop the field that's been tied back to by the newer well did it just take 2 years to develop that new production or 8 years...6+2? IOW the new reserves were too small to justify developing until the big infrastructure offsetting it was in place.

Not sure you can find the data but normalizing the development time to the initial bbls of oil per day might be mores illumination. IOW those short development times might also result in less bopd per year of development time.

A lot quicker to harvest 100 acres of corn then 1,000 acres. But you end up with a lot less corn. IOW quicker isn't always better...like with sex. LOL.

[Zarquon]

http://oilprice.com/Latest-Energy-News/ ... locks.html

"A total of 21 companies, including the Who’s Who of Big Oil, have registered to take part in Mexico’s deepwater oil auction to be held in December.

Shell, Chevron, ExxonMobil, British BP, French Total SA, Spanish Repsol, Norwegian Statoil and Mexican Pemex are among the major players now registered to bid for 10 blocks in the Gulf of Mexico, Prensa Latina reports.

Reserves in the blocks up for auction are worth an estimated US$10 billion, and this phase is being lauded as the most lucrative blocks. The blocks are in Perdido, near the US maritime boundary in the Gulf of Mexico, as well as in Cuenca Salina southward. Some 76 percent of the country’s potential oil resources are in the Gulf of Mexico’s deep waters"

And a day before, in the same magazine:

http://oilprice.com/Energy/Crude-Oil/Th ... cover.html

"Offshore production has lower decline rates than shale does, but considerably higher decline rates than onshore vertical developments.

It is hard to pinpoint these decline rates exactly since each field is unique. What the industry generally believes is that offshore production declines at twice the rate of conventional onshore.
...
The majority of the oil and gas sector is in serious financial difficulty. It will take a long stretch of sustained high oil prices before anyone gets bullish on deepwater exploration again.

Existing discoveries will be developed. Investing money in those situations provides a guaranteed return on investment through cash flow. Wildcat deepwater exploration is not a business that is coming back for a long time, if ever."

$10 billion of reserves in that block, at $50/bbl, that's 200 million bbl? Getting produced over perhaps ten years but fuels the world for not even three days.

And "offshore production declines at twice the rate of conventional onshore", why is that so? Is it the geology in these fields, or higher pressure at greater depths, or different reservoir management offshore, i.e. pushing for the highest flow rates to get a return on investment ASAP?

[Zarquon]

And one more:

http://oilprice.com/Energy/Crude-Oil/Oi ... oming.html

"Even existing oil fields that are actively producing oil could be shuttered earlier than planned because of low oil prices. Statoil announced recently that it could shut down its Veslefrikk oilfield much earlier than it originally had planned. That follows a previous decision to shut down its Volve field by the end of 2016, several years earlier than anticipated.

Several similar decisions are under consideration from other operators. In another example, Repsol shut its Varg field, a small 5,000 barrel-per-day field, five years earlier than it expected.

The problem with the North Sea is that the closure of one project can affect the economics of another as they share the costs of infrastructure. The result can be a domino effect. For instance, ExxonMobil is set to shut down its Jotun field in October, five years earlier than expected, but that means that Det Norske’s Jette field will also have to shut down because it was tied back to the Jotun B platform."

So the subsea tiebacks can make a project feasible in the first place, but also increase the long-term risk.

[Tanada]

$this->bbcode_second_pass_quote('Zarquon', 'h')ttp://oilprice.com/Latest-Energy-News/World-News/Over-20-Oil-Majors-Sign-Up-for-Mexicos-Most-Lucrative-Offshore-Oil-Blocks.html

"A total of 21 companies, including the Who’s Who of Big Oil, have registered to take part in Mexico’s deepwater oil auction to be held in December.

Shell, Chevron, ExxonMobil, British BP, French Total SA, Spanish Repsol, Norwegian Statoil and Mexican Pemex are among the major players now registered to bid for 10 blocks in the Gulf of Mexico, Prensa Latina reports.

Reserves in the blocks up for auction are worth an estimated US$10 billion, and this phase is being lauded as the most lucrative blocks. The blocks are in Perdido, near the US maritime boundary in the Gulf of Mexico, as well as in Cuenca Salina southward. Some 76 percent of the country’s potential oil resources are in the Gulf of Mexico’s deep waters"

And a day before, in the same magazine:

http://oilprice.com/Energy/Crude-Oil/Th ... cover.html

"Offshore production has lower decline rates than shale does, but considerably higher decline rates than onshore vertical developments.

It is hard to pinpoint these decline rates exactly since each field is unique. What the industry generally believes is that offshore production declines at twice the rate of conventional onshore.
...
The majority of the oil and gas sector is in serious financial difficulty. It will take a long stretch of sustained high oil prices before anyone gets bullish on deepwater exploration again.

Existing discoveries will be developed. Investing money in those situations provides a guaranteed return on investment through cash flow. Wildcat deepwater exploration is not a business that is coming back for a long time, if ever."

$10 billion of reserves in that block, at $50/bbl, that's 200 million bbl? Getting produced over perhaps ten years but fuels the world for not even three days.

And "offshore production declines at twice the rate of conventional onshore", why is that so? Is it the geology in these fields, or higher pressure at greater depths, or different reservoir management offshore, i.e. pushing for the highest flow rates to get a return on investment ASAP?

[ROCKMAN]

T - In general you're correct The LOE (Lease Operating Expense) of a DW field is huge compared to an onshore field. Huge on the order of 100X. Also good to note that old field economics are based upon the NPV...Net Present Value. A DW well producing 3 million bbls over 5 years is much more economic then one that takes 10 years. IOW production from a well beyond 7 years or so of its life adds very little to its NPV.

At the same time offshore LOE will result in much more oil left behind as uneconomic to produce. IOW there's no such thing as offshore stripper wells...nothing even close. Compare that to the significant volume onshore US strippers contribute. BTW they found numerous reservoirs in DW wells that will never be produced because they would flow to little. And "too little" could be 300+ bopd...a rate most onshore geo!ogists would give their left but for. LOL. Even on the less expensive shallow GOM shelf I've seen operators plug wells as dry holes that could have recovered 500,000+ bbls.

[wildbourgman]

From my perspective as a GOM oilfield worker this is the worst I've ever seen. The layoffs and firings have been prolific and the draconian cutbacks that lead to shortcuts that some of the top energy companies are performing are beyond belief. Some of it is borderline dangerous.

[ROCKMAN]

Yep. So much easier for companies to pull their necks back in. Unlike onshore where leases can expire in a few years many offshore leases can be extended as much as 10 years with little or no activity. Much better for pubcos to keep dividends up then pushing forward on production especially when future prices will certainly be much higher. Of course the lay offs are of no importance to management...as long as it's not them being mothballed. LOL.

[wildbourgman]

In some companies even the management isn't safe this time. That's a little different then before.

[Zarquon]

I didn't even realize how much production comes from offshore these days, how long it takes and how short production lasts. And with all these layoffs: if there's a price rebound in 2017 or '18, it would take the offshore sector a number of years to get into high gear again and start hiring. And after cutting loose tens of thousands of experienced workers and engineers years before - would they then still find enough crews to man all the new platforms, even with all the expensive automation going on? If I'm somehow understanding the dynamics now, the next cycle could happen as late as 2025. If you've been laid off in 2015 and haven't found anything in the shale fields, you've moved on for good by then.

[wildbourgman]

There are a lot of factors in order to even attempt a prediction. I think we'll have an uptick in price and activity to follow. Automation doesn't reduce employees on offshore drilling rigs for the most part, it makes them more expensive.

I don't see the finances being available to create another irrational boom anytime soon but who knows.

[ROCKMAN]

Z - Muscles are always available at the right price. But not experience. The withdrawal of the old experienced grayhairs has been excellerated by the bust. But you have to look back at the previous bust in the 80's. Today's senior management began their careers in the 70's. But relatively few entered the work force in the 80' and 90's.

If you plotted the ages of the current workforce there's a huge dip in the 40 to 60 range. The Rockman entered the oil patch "baby boom" in 1975. The Rockman and the vast majority of his peers won't be hunting for the grease in 2020+ regardless of the price of oil/NG.

[tita]

Eia monthly reports provide informations on GOM production. In december (last numbers), production reached 1'728 Mbbls/d. We have to go back to 2009 to find such levels, which were the all time highest.

BTW, monthly reports show that onshore production decreased by 140 Mbbls/d between november and december.

[ROCKMAN]

tita - Speaking of new wells not keeping up with depletion the situation has suddenly gotten worse in the Bakken. From Art Berman. A somewhat overly dramatic title IMHO:

http://oilpro.com/post/30230/beginning- ... ture_1_txt

The Beginning of the End For The Bakken Shale Play

"The decline in Bakken oil production that started in January 2015 is probably not reversible. New well performance has deteriorated, gas-oil ratios have increased and water cuts are rising. Much of the reservoir energy from gas expansion is depleted and decline rates should accelerate. More drilling may increase daily output for awhile but won’t resolve the underlying problem of poorer well performance and declining per-well reserves.

December 2016 production fell 92,000 bopd – a whopping 9% single-month drop (Figure 1). Over the past two years, output has fallen 285,000 bopd (23%). This was despite an increase in the number of producing wells that reached an all-time high of 13,520 in November. That number fell by 183 wells in December."

[ROCKMAN]

pstarr - You misread: last Dec (latest number) offshore GOM oil production reached an all time record high: 53.6 million bbls of oil.

https://www.eia.gov/dnav/pet/hist/LeafH ... fp3fm1&f=m

And one picky point: the GOM is not an "oil field" but a geologic basin containing many oil fields.

Also which play is bigger today? Prudhoe Bay has slipped behind two Texas oil trends that are at the forefront of the shale-oil revolution, according to the report, issued by the U.S Energy Information Administration, an agency of the Department of Energy. The nation's top ONSHORE oil play, in both remaining reserves and annual production, is Eagleville in Texas' Eagle Ford Shale Play. That play produced 238 million barrels in 2013, the EIA report said. In second place is the Spraberry Trend Area, which produced 99.78 million barrels in 2013, the EIA report said. Prudhoe Bay, which produced 79 million barrels in 2013, was in third place in both reserves and output, according to the EIA list.

Of course, the GOM basin beats the hell out of all three plays by currently producing about 600 million bbls of oil per year. Which explains how we've produced a TOTAL OF 13 BILLION BBLS OF OIL FROM THE GOM.

[Subjectivist]

$this->bbcode_second_pass_quote('ROCKMAN', 't')ita - Speaking of new wells not keeping up with depletion the situation has suddenly gotten worse in the Bakken. From Art Berman. A somewhat overly dramatic title IMHO:

http://oilpro.com/post/30230/beginning- ... ture_1_txt

The Beginning of the End For The Bakken Shale Play

"The decline in Bakken oil production that started in January 2015 is probably not reversible. New well performance has deteriorated, gas-oil ratios have increased and water cuts are rising. Much of the reservoir energy from gas expansion is depleted and decline rates should accelerate. More drilling may increase daily output for awhile but won’t resolve the underlying problem of poorer well performance and declining per-well reserves.

December 2016 production fell 92,000 bopd – a whopping 9% single-month drop (Figure 1). Over the past two years, output has fallen 285,000 bopd (23%). This was despite an increase in the number of producing wells that reached an all-time high of 13,520 in November. That number fell by 183 wells in December."