Drill, baby, drill

Now, would they be doing this if we had an 'oil glut'?

Offshore oil rigs drilling deeper than ever

Booming like never before, the offshore oil and gas industry is exploring ever deeper into the ocean and drilling further under the sea bed, bringing strikes like one this week off Brazil, which may be one of the biggest yet in the region.

The Globe and Mail,

14 August, 2012

“Ultra-deep” wells, drilled in water at least 1.5-kilometres deep into several more kilometres of rock to the reservoir below, have reached a landmark in 2012 to date, accounting for more than half of all the world’s new discoveries so far this year, data from IHS Offshore Rig Consulting shows.

And from a global fleet of more than 1,200 rigs and drilling vessels tracked by rigzone.com, more than 80 rigs on contract now have the ability to work in ocean depths of more than 2,300 metres. That compares to fewer than 10 at the turn of the century and double the number at work just two years ago, IHS says.

It is not hard to see where the funds are coming from: The world’s biggest offshore oil players, from the likes of BP PLC, Royal Dutch Shell PLC and Chevron Corp. to national oil companies with promising offshore waters such as Petrobras in Brazil, India’s ONGC and Mexico’s Pemex – are using the proceeds of high oil prices to spend at a pace.

Petrobras’s new Carcara strike was two kilometres below the surface of the Atlantic in an area causing much excitement.

Data from analysts at Wood Mackenzie puts total exploration spending among the Western oil majors alone at more than $80-billion (U.S.) this year, more than four times the level in 2002 – and up 25 per cent compared to 2010. Much of that is going offshore, and the results are coming thicker and faster than many expected.

As well as the news from Brazil, this week also saw unexpectedly strong results announced by Norwegian oil services company Aker Solutions, an offshore specialist.

“The market seems better than anyone had hoped,” said Christian Frederik Lunde, an analyst at brokerage Carnegie.

The factors driving private oil and gas companies into the ocean have been around for decades: Resource nationalism denies them access to three-quarters of the world’s known reserves, the economics and politics of offshore development are simpler than on land, and the finds are big and economically viable.

A sustained period of high oil prices have pushed this latest boom, but technological breakthroughs have accelerated it, too.

This week’s Brazilian breakthrough is an example. Drilled in 2,027 metres of water to a depth of 6,213 metres, the Carcara well is in a so-called subsalt field, underneath salt layers that once hid the hydrocarbon deposits from seismologists.

It was all so different 30 years ago, when the North Sea between Britain and Norway was still new exploration territory.

Engineers wondered then how they would ever drill from a sea bed deeper than a man could dive, and into reservoir pressures that would be higher than that diver’s oxygen tank.

“We thought we were pretty amazing when we did it,” recalls Eamonn O’Connell, a veteran of the pioneering era and now BP’s director for well interventions and integrity.

Today, those achievements in 140 metres of water look like child’s play beside wells in the deep oceans. The world’s deepest offshore production well, operated by Shell from the Perdido platform in the U.S. Gulf, is 9,356 feet – almost three kilometres – below the waves.

The water pressure alone at that depth is 4,500 pounds per square inch (psi), or 310 bar – similar to that inside those North Sea wells of the 1980s. The reservoirs themselves in the U.S. Gulf, off West Africa, Brazil and elsewhere, are several kilometres deeper again below the seabed, testing engineering ingenuity at pressures up to 18,000 psi – more than three times what the North Sea geologists had to worry about.

The risks are great, as demonstrated by BP’s Macondo well, of 2010 Gulf oil spill infamy. Drilled in just below 1,500 metres of water and encountering pressure of 12,000 psi, it was not a record breaker. Yet the Transocean-managed Deepwater Horizon rig exploded, killing 11 people. The pipework collapsed, buckling, and the blowout preventer failed.

A spewing, broken Macondo took months to cap, set off the United States’ worst offshore environmental disaster, and is set to cost BP billions of dollars in compensation and fines. It also overshadows the financial future of Transocean, the world’s No. 1 rig operator.

But the potential rewards offshore are equally enormous.

Since 2002, WoodMac data shows, the average “shelf,” or shallow offshore exploration, well has added 21 million barrels of oil equivalent (boe) in reserves, compared with just 12 million for the average conventional onshore well.

In deep water – defined as deeper than 1,200 feet – the average leaps to 55 million boe. IHS data maps the average ultra-deep find, 1,400 metres down, higher again – at 140 million.

That is 11.5 times more effective than an onshore rig, and at $100 a barrel, amounts to $14-billion worth of oil per discovery in the ultra-deep – enough to repay a whole year of capital spending for some of the world’s top oil companies.

“It’s not too surprising. The deeper you go, the bigger the reservoir you need to make drilling worthwhile,” says IHS data analyst Tom Kellock. “The good news is, people are finding what they are looking for.”

For all the potential foreseen for onshore shale techniques in the United States, there is nothing marginal about the importance of offshore oil and gas to future energy supplies.

On a production basis alone, WoodMac expects known deep and ultra-deep offshore finds to be producing twice what they are today in 10 years time, at 15 million boe of oil and gas a day. That is double last year’s total U.S. oil output.

Thunder Horse in the U.S. Gulf is BP’s flagship well for the ultra-deep generation. The company’s Eamonn O’Connell kisses his fingertips in fond recollection of the quality of the 1999 discovery which eventually went into production in 2008.

The Thunder Horse platform is not in the deepest water, at 1,800 metres feet, but the wells it serves extend as much as 5,800 metres below the seabed and are among the deepest ever drilled, on- or offshore.

The well pressures range from 13,000 to 18,000 psi at temperatures up to 132C – right at the limit of current offshore capability.

They are not stopping here.

BP launched this year a project it calls 20K – aimed at the next generation of even deeper, higher pressure, higher temperature wells at pressures of more than 20,000 psi.

Supercomputers, new materials, coatings and sub-sea sensors are being developed to exploit oil at these depths, and platform designers are looking at basing more gear on the sea floor so that pressures can be reduced on the way to the surface.

Quite what will be possible is unclear. For the energy to be harnessed, engineers will have to get amazing again.

Shale oil everywhere… for a while

FT,

13 August, 2012

The US is going to be free from the tyranny of imported crude oil soon, according to just about everyone. This is thanks to the wonders of shale gas extraction technologies being applied to sizeable and mostly untapped shale oil reserves. Previously marginal resources can now be economically extracted. Even the Europeans are getting excited about it. It’s a game changer.

You can probably guess what’s coming next…

Bernstein Research’s Bob Brackett (H/T Steve Levine) has an interesting note which examines the performance of shale oil wells in the Bakken formation. While the formation is in both Montana and North Dakota, Brackett narrowed his analysis to those in the former state.

There are high hopes for future output of the Bakken shale, which is why a graph like the below is disconcerting:

The decline cannot be explained simply by the number of wells being operated — because those have increased. A per-well average looks like this:

Writes Brackett:

Remember that over this same time period, the E&P industry invested hundreds of billions of dollars in horizontal drilling and hydraulic fracturing, rolling out new innovations and new completions techniques, longer laterals, higher stage counts, etc.  Yet this wave of innovation was insufficient to increase average well productivity.

But despite these efforts, the average well maintains its healthy production for a short time:

Another point we make concerning these Bakken wells is how rapidly they become stripper wells. Exhibit 6 shows a Bakken type curve for horizontal wells.  We are accustomed to the high early rates, fast decline.  The type curve shown has a cumulative EUR of roughly 250,000 barrels of oil.  Exhibit 7 shows the same type curve in logarithmic scale. This allows us to identify the time at which a Bakken well becomes a stripper well – 6 years into production.

 

That’s it — a mere six years to “stripper” status.

 

Two-hundred modern Bakken horizontal wells are now strippers, says Brackett. He has some other interesting little facts: these ‘stripper’ wells initially cost about $10m to drill and have a lateral length of almost two miles. Once they hit “stripper” status of about 15 barrels/day, they produce oil “at the same rate that rain falls in Seattle”. They can keep producing for years at that rate, of course — as long as it’s economic to do so. A quarter of the expected output from a Bakken well will be delivered during its post-peak “stripper” phase.

Brackett stresses he’s not a peak oilist or saying that the end is nigh…

We do believe US oil production will grow over the next several years and that the Bakken and Eagle Ford will become million-barrel-a-day fields, which is in and of itself an outstanding achievement.  But in terms of investment philosophy, we still maintain that (a) the world will not find itself awash in oil (shale or otherwise) and thus we remain bullish on long term oil price, and (b) oily resource plays are rare and the market will ultimately reward those companies that were most successful in establishing positions in the heart of these opportunities.

However he told Steve Levine of Foreign Policy’s (recently closed) Oil & Glory blog that he does believe this trend will hold for the Bakken shale formation in North Dakota, too — on which, as Levine points out, many of the North American oil production forecasts rely.

Right now, just 200 modern Bakken wells are strippers. But in roughly six years, there will be 4,000 of them, Brackett says. “All good things in the oil patch come to an end,” Brackett told me. “In the case of North Dakota, that is a long time — years — off, but even that too will suffer the same fate” as Montana.

 

While we’re raiding Levine’s posts, he has this prize quote from veteran oil watcher Phil Verleger whom we sometimes feature here on FTAV. Asked by Levine about the forecasts of a US ‘golden age of oil’, Verleger responded (emphasis ours):

Lastly, shale oil production will increase. How much — I am not sure. I am an econometrician and the builder of the first energy models back in 1971-1975.  I have learned though experience that energy models are the most expensive, most cumbersome random number generators ever invented. Three years ago, I would have predicted little output from shale oil.  Now I read forecasts that there will be large supplies. I do not know.

A timely reminder indeed.