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One of the live oaks that bless my home

Friday, May 4, 2012

Peak Oil? - In Norway

Who would you rather believe, a renowned professor at BI Norwegian School of Management and consultant to IMF, The World Bank, the governments of Denmark, Norway, Canada and the U.S., etc., or your own lying eyes? If you follow the April 2012 issue of the World Oil, the good professor wins.

After having read the convincing "Peak Oil? - Not in Norway" piece in the World Oil, you may want to recalibrate your senses by looking carefully at the four graphs below. Click on each one of them if you want to see a high-resolution image.
Oil production rates from the North Sea and Norwegian Sea oilfields on the Norwegian continental shelf are a set of 65 approximately independent random variables. The total production from these 65 fields is then a random-sum process that yields a Gaussian distribution, in this context known as a "Hubbert curve" or "Hubbert peak." The thick blue line is the rate of oil production from Ekofisk. The Ekofisk production curve has two peaks and is highly asymmetrical. Note that in 2007, the Ekofisk field was producing at a higher rate than in 1978. This means that Ekofisk will continue to produce substantial amounts of oil for years to come. Data sources: The Oil and Gas Journal (2009), The Norwegian Petroleum Directorate. For more discussion, see Appendix A in Patzek and Croft (2010).
The cumulative oil recovery from Ekofisk (the area under the thick blue line in the plot above) expressed as a percent of the oil in place (OIP). Oil production started at Ekofisk in 1972, as a compaction drive. The reservoir pressure decreased below the bubble point (gas started to evolve from the depressurized oil) in 1976. The solution gas drive production peaked in 1978, and water injection to maintain the reservoir pressure and displace more oil was started in 1983. Since 1995, horizontal wells, multilateral wells, and infill wells have been drilled. The cumulative oil production reached 40 percent of OIP by 2007, and was still going up nicely. Because of the improvements in well technology and secondary recovery processes, Statoil expects to recover well above 50 percent of OIP from Ekofisk. And this will be a world-class achievement of petroleum engineering.
When oil production rates from all the 65 fields in the first graph are summed up, a fundamental Hubbert curve emerges with a clearly visible peak in 2001-2002.  The most recent data (the blue step line) from the Energy Information Administration end in 2011.  The new deposits of oil in the old fields - accessed with waterfloods and smart multilateral wells - give rise to the small blue Hubbert curve that in no way can reverse the overall decline.

The same data and Hubbert curves as in the graph above, but now we assume that an additional 7 billion barrels of oil will be rapidly produced from the newly discovered and undiscovered reservoirs in the North Sea. Today there are 51 active oil and gas fields on the Norwegian continental shelf, and even after 35 years of production the Norwegian Petroleum Directorate believes that Ekofisk still has the largest reserves. In total, nearly 40 percent of the discovered marketable oil resources on the Norwegian shelf have not yet been extracted, they say. In addition, there are probably many undiscovered fields. The Petroleum Directorate estimates that the undiscovered resources alone amounts to 7.3 billion barrels of oil.  Read more here. You may agree that the peak of the total oil rate from the Norwegian offshore fields was reached in 2002, assurances to the contrary by the good Norwegian professor notwithstanding.

So here is the bottom line:
  • Am I suggesting that no more oil will be discovered on the Norwegian continental shelf, especially up north towards the North Pole?  Of course I am not, and significant new oil will be discovered.  
  • Will the ultimate oil production from the Norwegian shelf be more than shown in the last figure?  Yes.  
  • Will Statoil and other operators be able to reverse the generally declining production rate and exceed the 2002 peak?  Almost certainly not.
  • Will Statoil rest on its considerable laurels?  Never. Statoil is rapidly expanding its operations to North and South America, and Africa.  Statoil's research budget in North America is now 1/2 of its global research outlays. 
  • Do most professors of management, and IMF or the World Bank experts, understand rudiments of oil production?  Choose your answer carefully, because this is a test.  If you answered "no," you passed.  

Monday, April 30, 2012

The Discrete Charm of Living at the Peak

In the summer of 1858, Edwin Drake punched 33 ft of cast iron pipe into the earth to prevent near surface water from collapsing the hole. He then lowered drilling equipment into the cased hole and used a steam engine to drill a successful, 69 ft deep well. On August 27th, shallow oil flowed almost to the surface and was recovered with a sump pump. Edwin Drake made absolutely no money on developing modern drilling technology and died a poor man.

The North American oil industry four years after Drake's well. The Phillips well is on the right, and the Woodford well on the left. Located in the middle of Oil Creek Valley (note the river at the right of the photograph), these two wells showed the early promise of the Oil Regions. The Phillips well was the most productive ever drilled to date, flowing initially at 4,000 barrels per day in October 1861. The Woodford well came in at 1,500 barrels per day in July, 1862. Source: Drake Well Museum Collection, Titusville, PA.

On January 10, 1901, captain Anthony F. Lucas drilled a well to a depth of 1,139 ft (347 m) near Beaumont, Texas. By chance, he created the "Lucas Gusher" that blew oil over 150 feet (50 m) into the air at a rate of 100,000 barrels per day (4,200,000 gallons per day). Because of that spectacular event, the modern oil industry was born overnight. By the end of 1902, more than 500 companies had been formed and 285 wells were in operation. Captain Lucas died penniless.

The Lucas Gusher, 1901, Photograph, 1901; digital image, (http://texashistory.unt.edu/ark:/67531/metapth41398/ : accessed April 30, 2012), University of North Texas Libraries, The Portal to Texas History, crediting University of Texas at Arlington Library, Arlington, Texas.

Now I want you to read loudly this magic word:

"Technology."

Did you hear yourself? Was the sound of your voice soothing? Almost like experiencing a church mass on a Sunday morning? If the answer is yes, you are one of the 300 million Americans, who religiously believe in the magic of technology that will see us through any difficulty whatsoever with almost no pain and multiple gains.

Enter the modern oil and gas industry in the year 2012.  Yes, my industry has created an unbelievable technology to invade the most inhospitable environments ever encountered by humans.  We now use the super machines that put to shame the U.S. space program and, in particular, the Apollo missions.

The Troll A platform is a concrete offshore natural gas platform in the Troll gas field off the west coast of Norway. It is the tallest construction that has ever been moved to another position, relative to the surface of the Earth, and is among the largest and most complex engineering projects in history.

Imagine that using this miraculous technology humanity's deep ocean scouts, otherwise known as the "Super Majors" and "National Oil Companies," decide to drill in 10,000 feet of water a 25,000 feet-long well that may encounter pressures of up to 20,000 psi and temperatures above 350 degrees Fahrenheit.  That well will be drilled 200 miles offshore by a giant, semi-submersible drill ship that costs 700 million dollars, and is operated by a crew of 200 people and dozens of people onshore, who watch the functions of the ship 24/7 via satellite links and massive computers.

Twenty five thousand feet (7,620 meters) is much taller than Mount McKinley and as tall as Gonga Shan (Minya Konka) in the Szechuan Himalayas.  On the seafloor, the well will be protected by a newly designed blowout preventer (BOP) rated to 20,000 psi. This BOP may weigh 500 tons and be 70 ft tall.  It will be quite a chore to transport this new BOP offshore and lower it through 10,000 ft of seawater onto a well head that might be 3-4 ft in diameter. The 20,000 psi BOPs do not exist yet and may be too large to fit inside the existing drill ships.

Now try to imagine 25,000 feet of high quality steel casing pipe, starting from the inner diameter of 36 inches or more, because its walls might be thicker and we still want to land a 7 inch pipe at the depth of 25,000 feet sub-seafloor.  Then imagine 25,000 feet of the thick-wall, steel production tubing that will be placed inside this casing to conduct flow of a supercritical hydrocarbon fluid, while undergoing wrenching thermal and chemical stresses for years.  Picture how difficult it will be to pump cement through 35,000 feet of drill pipe and return it along the fragile narrow space between the casing and the open hole.

One of the four new
ultra-deepwater drill ships for Noble Corporation.

When this well is successfully completed (do you see the risks?), it and other similar wells will produce through a giant floating platform that might cost 1,000 million dollars and employ many dozens of highly skilled personnel flown in-and-out by helicopters.

Let us go back to Colonel Drake and his technology.  Do you see the fundamental difference between producing 20,000 barrels per day of shallow oil from 5 simple wells that may cost 0.04 million dollars each, versus 20,000 barrels of ultradeep oil and gas from one well that will cost 200-300 million dollars?

In the first case, the initial and ongoing expenditures of energy were nothing compared with the heating value of the oil.  In the second case, in addition to the well hardware, we need to throw in two hundred miles of a seafloor steel pipeline or a bunch of tankers, seafloor facilities, ships, and other energy-intensive means of assuring production from our well for a few years.

Net energy gain from the ultradeep wells can be much, much less than producing the old East Texas oilfields.  Net energy gain from the various oil and gas shale projects can be less yet. And this is the main energy problem the twenty first century Earthlings face.  Most are ignorant, others are in denial.  The current state of affairs is not a prescription for a meaningful social discourse on what to do next, when the current global economy is strangled by the lack of cheap reliable crude oil. For those in chronic denial, please note that I said "when," not "if."

P.S. What I just showed you is translated into the official business language as follows:
Our analysis of the 50 largest publicly traded oil and gas companies (ex-FSU) shows that cost inflation continues to increase sharply within the global upstream oil and gas industry. In 2011, production costs increased by 26% while the unit cost of production increased by 21%, which was higher than longer term trends. In 2011, the marginal cost of production the same companies increased 10.8% to US$92.26/bbl.
"Era of Cheap Oil Over As Secular Growth in Upstream Cost Inflation Underpins Triple Digit Oil Prices," Bernstein Research, May 2, 2012.

Do not feel guilty if you can't understand this quote, but it surely is scary when you superimpose it on top of the actual declines of production by most major oil companies.