There are a number of agencies that produce short- and long-term crude oil forecasts, including the U.S. Department of Energy’s Energy Information Agency, OPEC, and the International Energy Authority.  Deutsche Bank analyst Michael Lewis has now called the accuracy of these forecasts into question.   From a recent article in the Oil & Gas Journal:

In his assessment of global oil demand and non-OPEC supply growth, Lewis found that, with the exception of 2003-04, all three agencies have been too optimistic about the strength of oil demand, with OPEC the most cautious. All three agencies have been too optimistic about non-OPEC production growth, with DOE the least bullish and therefore the most accurate in its forecasts.

Concerning global oil demand growth since 2001, Lewis found that forecasts have been “quite similar” in their under or overestimation, with OPEC the most accurate over the decade. Lewis worked out that in absolute percentage terms, since 2002 OPEC has averaged a forecasting error of 53.5%, compared with IEA’s and DOE’s error rates hovering at 70-75%. OPEC’s greater demand forecast caution “may help to explain its reluctance to increase oil quotas and production for fear of bearish implications for the oil price,” said Lewis.

However, in 2003-04, “all three agencies underestimated the surge in global oil demand and specifically the strength in Chinese and US oil demand during those years,” he noted. The discrepancy was large in 2004 as DOE forecast demand growth of some 1.6 million b/d whereas the actual increase exceeded 2.5 million b/d. In contrast, in 2005 DOE overstepped market demand accuracy by forecasting a 2 million b/d growth compared with the actual 1.3 million b/d.

Regarding oil production, all three agencies’ forecasts were relatively close to actual non-OPEC growth, which was averaging 1 million b/d for each year during 2001-04. But 2005 was the worst forecasting year as non-OPEC oil production fell to roughly 0.4 million b/d and the three agencies failed to change their growth assumptions, forecasting a non-OPEC production rise of 0.93 million b/d. Since then, non-OPEC growth levels have failed to recover the early decade levels.

DOE has tended to be the most accurate production forecaster: Since 2001 DOE has posted a forecasting error of 51% compared with 63% for IEA and 72% for OPEC.

Looking into 2009 and taking into account the removal of fuel subsidies in many parts of the developing world, Lewis sees DOE’s 1.4 million b/d oil demand forecast growth as “likely to be too optimistic and even the 0.9 million b/d assumed by the IEA and OPEC may prove too ambitious if recent history is a guide.” He said he expects the recent non-OPEC oil production rebound since 2005 set to continue in 2009.

This may require some recalibration of the models…

As world production of light sweet crude oil declines, everyone is looking at “unconventional” oil sources to take up the slack.  “Unconventional” includes sources like heavy oil (warm thick goop), cold oil (cold thick goop), oil sands (thick goop mixed with dirt), and oil shale (solid goop).  Their common characteristic is that, compared to light sweet crude (think motor oil), they are harder (and more expensive) to produce.  Think of the difference between pumping motor oil compared to pumping asphalt.

Alaska’s North Slope is no different.  ANS blended crude, the stuff that gets pumped down the Trans-Alaska Pipeline and loaded onto oil tankers in Valdez, is currently a blend of light to medium crudes that flows pretty well.  But the future of the North Slope will increasingly be made up of shallow cold oil and deeper heavy oil.

BP is currently exploring the Ugnu formation, 4,200 down, drilling from S-Pad at Milne Point.  The plan is to use a down-hole pump to produce the oil, which has been described as having the consistency of chocolate syrup.

From Petroleum News:

An initial test should take about three weeks, with a phase one testing project continuing into 2009 and involving the drilling of three more wells by the end of 2008, Eric West, BP’s heavy oil project manager, told a media tour of the Milne Point test facility Aug. 18.

If the phase one testing demonstrates the technical feasibility of heavy oil production, the project will move into a second phase of testing, to evaluate whether heavy oil production at Milne Point will prove economically viable, said Max Easley, Alaska Consolidated Team business unit leader.

The Ugnu formation is estimated to contain roughly 20 billion barrels of heavy oil, so there is a lot of interest in the test.

The oil in the Prudhoe Bay region has migrated into various reservoirs at different depths. But bacteria that become particularly active in the temperature conditions at depths of around 4,000 feet eat out the lighter hydrocarbons, West said. That results in a residue of heavy oil in relatively shallow reservoirs far above the conventional light oil reservoirs of the North Slope oil fields.

Methane waste from the bacterial action bubbles towards the surface and becomes trapped around the base of the permafrost as gas hydrate, West said.

About three years ago BP decided to embark on a project to try to develop the heavy oil while there is still significant production of light oil from the North Slope. The light oil is needed to thin the heavy oil so that the resultant fluid can flow down the trans-Alaska pipeline, West explained

“We need the light oil to blend it with, so it’s the perfect time in the North Slope’s life,” Easley said.

Were BP to stick to the conventional concept of waiting for depletion of the North Slope light oil before producing the heavy oil, the company would have to resort to an expensive technique such as hydrogen cracking to create a light enough fluid for export by pipeline, West said.

Of course the big unanswered question is how to get the oil to the surface.  There are several options.

The most widely publicized methods consist of either the surface mining of oil sands or the application of heat to the underground reservoirs, West said. However, in Canada, the epicenter of heavy oil development, techniques for cold heavy oil extraction have also been developed, he said.

BP has a policy of not mining for heavy oil, West said. But the choice between hot and cold in-situ production depends on the nature of the oil reservoir and the characteristics of the oil, he said. On the North Slope much of the Kuparuk unit area heavy oil appears most suitable for hot extraction, while in the Prudhoe Bay and Milne Point units cold techniques seem more appropriated.

West also said that cold techniques create a smaller carbon footprint than hot techniques.

The particular technique that BP has chosen to try at Milne Point is called cold heavy oil production with sand, or CHOPS, a technique that has seen several commercial developments in Alberta.

In this technique, which depends on an unconsolidated sand reservoir, the production well has large perforations and no screen for keeping the sand out of the well. Sand is produced along with the oil and is subsequently separated from the oil at the surface by heating the oil/sand mixture in a tank.

“You’re actually producing a bit of the reservoir into the wellbore,” West said. “That is totally contrary to light oil reservoirs where you always want to keep the sand out.”

So if the oil you’re planning to pump flows like wet cement, and has grit, sand, and gravel in it like wet cement, how do you pump it?  With a cement pump (aka progressive cavity pump) of course, just like a cement truck does.

A key part of the well technology is the downhole pump, known as a progressive cavity pump, consisting of a long augur-like rotor that spins at high speed inside an enveloping tube. The rotating augur screw will draw material up the well, while being less susceptible to wear than a piston-based pump design.

Because the sand in the well would tend to cause a downhole electric motor to overheat, the pump’s motor drive is placed at the surface and is connected to the pump rotor by means of a long rotating rod that extends through the well inner casing. A huge spool called a mobile gripper unit feeds the drive rod down into the well casing.

The pump should cause a pressure drawdown or drop of around 1,000 pounds per square inch or more at the bottom of the well.

“We’re going to put really significant drawdown against these open perfs,” West said. “And that’s going to induce the formation to produce into the well.”

Once a well goes into operation, initial sand production should be high, perhaps 40 percent of the total production volume, said Grant Encelewski, operations lead tech for the BP heavy oil team. Then, after a system of fissures and wormholes in the reservoir has opened up and somewhat stabilized, sand production will drop to 10 percent or less, with a corresponding increase in oil production.

Since this is the first application of the technology in Alaska, there are a few hurdles to overcome.

Assuming that the initial well configuration works successfully, the team will try to improve flow rates — higher than normal cold heavy oil production rates will be needed to offset high Alaska well costs. The technique of choice for flow rate optimization is the use of multilateral horizontal wells but no one knows whether the sand production will work through horizontal well bores.

“No one has yet determined how you can pull sand along a horizontal well,” West said. “That’s our technology challenge.”

And one key factor will be the use of good reservoir imaging from seismic data to enable precise well placement.

“In Alberta they have a 40 percent (CHOPS) well failure rate,” West said.

The project team will try to apply innovative technologies to reduce costs. And, finally, the team will need to ensure that the footprint of the required surface equipment is acceptable.

By crossing these various hurdles, BP expects to overcome the two major challenges of heavy oil production: high production costs resulting from the high oil viscosity and the relatively low value of the product. Because the heavy oil contains a smaller proportion of high value products such as gasoline than light oil, BP expects the North Slope heavy oil to sell at about $9 per barrel below the regular price for Alaska North Slope crude. But at current oil prices, the economics look good, West said.

The bottom line:

“Without the heavy oil the future of Alaska is very much one of diminishing light oil, but then gas coming on big,” West said. “But with heavy oil you … have a rejuvenation of the fluids business for Alaska, and it becomes as much a fluids future as a gas future.”

From McClatchy Washington Bureau, a report by Tom Lasseter that Russia is lagging behind in developing new oil fields, thus endangering their oil income and world oil prices.

The Russian oil boom, which has produced a gusher of cash, political power and an opulent elite — and has helped fuel the country’s renewed assertiveness in Georgia and elsewhere — is on shakier ground than officials in Moscow would like to admit.
Most of the oil produced after the country’s 1998 financial collapse has come from drilling and re-drilling old Soviet oil fields with more advanced equipment — squeezing more black gold out of the same ground — and efforts to develop new fields have been slow or non-existent.
That strategy is potentially disastrous, said Valery Kryukov, who researches oil companies in western Siberia for a government-funded think tank.
“If the situation which exists now stays the same, oil production will start to decline seriously in two years,” Kryukov said in a phone interview from his offices in the city of Novosibirsk.
The implications extend far beyond Russia’s borders. Last year, Russia was the world’s second-largest oil producer. If its output begins to decline or is hampered by inept or corrupt business practices, the price of oil could begin climbing again.

Here’s the accompanying graphic:

How Long Will Russia's Oil Last?

The article notes that:

The government declared oil to be part of a “strategic sector” in which foreign investors need permission from the government before they can buy a significant stake in companies. Foreigners have been steadily shoved out, including a recent incident in which the head of the joint Russia-UK company TNK-BP, one of the country’s leading oil concerns, and 148 specialists left the country after their visa status was called into question.

In the short-term, business has been lucrative: Russian oil output jumped from about 6.1 million barrels a day in 1998, when the price of a 42-gallon barrel was less than $20, to an average of some 9.7 million barrels a day in the first half of this year. Prices reached $145 a barrel in July before dropping back to the $120 range.

At its current rate of production, though, Russia will run out of oil relatively soon, in about two decades, according to BP statistics. Saudi Arabia — last year’s biggest oil producer — can continue pumping at its current clip for about 70 years, according to the same BP statistics.

A chart provided by the U.S. Energy Information Administration lays out the stark details: Only two of Russia’s 14 largest oil producing fields were opened after the Soviet Union collapsed in 1991, and half of the 14 were more than 60 percent depleted in 2006. As fields are depleted, pumping oil out of them generally becomes harder and more expensive.

After a decade of oil production increases, there’s been a slight drop — 0.5 percent — in production during the first seven months of this year, according to state statistics. Troika Dialog, Russia’s largest investment bank, is forecasting a 0.7 percent decline in oil production this year from 2007.

From Upstream:

ExxonMobil says it is poised to launch a new $1.3 billion plan to develop the field, the first exploration since 1982. The company plans to build nearly 50 miles of ice road and an ice air strip and start drilling exploration wells this winter, the first wells to be drilled since 1982. Some contractors have been hired and, ultimately, 200 people will be employed on the work, which will prepare for oil production that is scheduled to start in 2014, the company told Reuters.

However, the state says ExxonMobil and its joint venture partners no longer own the Point Thomson leases. The Alaska Department of Natural Resources formally revoked the leases, some of which date back to the 1960s, for what it claims is non-performance by ExxonMobil and the partners.

The leases were revoked after the state rejected the 22nd and 23rd plan of operations submitted by ExxonMobil to the state.  The 21 consecutive previous plans were approved by the state but ExxonMobil never carried through on them and they expired.

The Point Thompson field lies along the coast just west of the Arctic National Wildlife Refuge.  It is considered a primarily gas field, with associated oil reserves.  The Alaska Department of Natural Resources estimates that the field may hold 580 million to 950 million barrels of oil and 490 million to 600 million barrels of natural gas liquids.  ExxonMobil holds the position that the field is not economically viable for development until there is a natural gas pipeline, either the Denali pipeline or AGIA, available to transport the gas to markets in Canada or the lower 48.  The state maintains that, under the state lease terms, ExxonMobil is obligated to produce the oil reserves in the field or relinquish the leases (State decision documents here).

The company has obtained a couple of permits from the state for surface work: one for water use and one that allows staging of equipment, fuel and a work camp, Exxon will not be allowed to drill any wells or do any subsurface work on what is now referred to as the “former Point Thomson unit,” state officials said.

“They won’t be issued any permits that are contingent on having leasehold rights,” said Nan Thompson, petroleum manager for the department’s Division of Oil and Gas. “So anything they do is at their own risk as to whether they will regain those rights.”

“We have the right to conduct drilling activities under the terms of the leases, which we do not believe have expired,” company spokeswoman Margaret Ross said in an email sent earlier this month.

ExxonMobil is already preparing a rig, has ordered materials and has awarded contracts to Alaska companies doing preparatory work “for the multi-well drilling program”, Ross said.

The state’s efforts to revoke Point Thomson leases started in 2005 when the Division of Oil and Gas rejected ExxonMobil’s 22nd consecutive plan of development for the field. In that plan, ExxonMobil and its partners declared that development would have to wait for a natural gas pipeline, a project estimated at the time to cost over $20 billion.

The state subsequently rejected ExxonMobil’s 23rd plan of development for Point Thomson, which calls for production of at least 10,000 barrels of liquids per day by 2014.

ExxonMobil and its partners have challenged the state’s actions.

The dispute over Point Thomson leases is now pending in Alaska Superior Court. State officials have predicted the issue will be resolved in the courts in about two years and that there will be ready buyers once the leases are put back up for auction.

There’s a lot of political wrangling going on here.  All sides agree that Point Thompson is essential for a natural gas pipeline and that tying the leases up in court will delay field development and the availability of natural gas for the pipeline.  But the state does have a point:  the leases do require development or forfeiture, and ExxonMobil has sat on some of the leases for over thirty years, despite repeated findings that oil production from the field was economical.  Until the state actually revoked the leases, ExxonMobil had no intention of doing any exploration or production.   ExxonMobil is now playing the bully card, which is status normal for them.

A previous post on this topic is here.

Here’s the latest numbers from the U.S. Energy Information Agency:

Canada remains the largest supplier of oil to the U.S., but Saudi Arabia has now displaced Mexico as the second-largest supplier.  No doubt part of this is due to the decline of the Cantarell field, which is in steep decline.

Update:  From Upstream, Mexico’s crude oil production has dropped 10% compared to last year:

The country’s state-run oil monopoly says it produced 2.84 million barrels of oil daily in the first seven months of the year.

The drop caused exports to fall 16.3% over the same period, for an average of 1.44 million barrels a day.

At the same time, oil export revenues climbed to a total of $30.1 billion, 52% higher than a year before. The rise is driven by high oil prices, said the Associated Press.

Experts say Mexico’s proven reserves will last only 10 more years.

President Felipe Calderon is pushing to allow more private investment to boost production.

Any decline in Mexico’s oil exports to the U.S. does not bode well for us.  Canadian imports have stayed pretty flat, so any reduction in Mexican imports would likely be made up of imports from less stable countries.  If Saudi exports peak (a distinct probability, given the status of the Ghawar field (see here)), oil imports will likely become unstable, which will lead to wide swings in crude oil prices.

I’ve blogged a few times before about Arctic sovereignty (here and here), and how it’s related to the potential for oil and gas development (here and here).  Now the International Boundaries Research Unit of Durham University has weighed in on the issue.  Their report is here.

IBRU Map of Arctic Sovereignty Claims

Compare this to the presumed locations of oil and gas provinces in the Arctic (Courtesy of the Arctic Council Emergency Prevention, Preparedness and Response Program).

Arctic Resources

It looks like the Barents Sea may become a point of confrontation between Russia and the West.  The Russian area has most of the presumed gas, Canada, Denmark, and the U.S. have most of the presumed oil.  This fits in with the USGS report. 

The IBRU notes that

In August 2007 Russian scientists sent a submarine to the Arctic Ocean seabed at 90° North to gather data in support of Russia’s claim that the North Pole is part of the Russian continental shelf. The expedition provoked a hostile reaction from other Arctic littoral states and prompted media speculation that Russia’s action might trigger a “new Cold War” over the resources of the Arctic.

While there are a number of disagreements over maritime jurisdiction in the Arctic region - and potential for more as states define the areas over which they have exclusive rights over the resources of the continental shelf more than 200 nautical miles from their coastal baselines - so far all of the Arctic states have followed the rules and procedures for establishing seabed jurisdiction set out in the 1982 United Nations Convention on the Law of the Sea. To date, only Russia and Norway have made submissions to the United Nations Commission on the Limits of Continental Shelf, but Canada, Denmark and the USA are also likely to define their continental shelf limits over the next few years.

In response to numerous enquiries relating to maritime jurisdiction in the Arctic, IBRU has prepared a map and a set of briefing notes on the current state of play in the region. The map identifies known claims and agreed boundaries, plus potential areas that might be claimed in the future.

For more information, see the IBRU report or the Toronto Star article here.

Courtesy Reuters, via Upstream Online, the latest crude oil prices:

Daily Crude Oil Prices, 15 August 2008

Y-axis is US$.  It looks like the price is dropping, perhaps in response to decreased demand in the U.S. and elsewhere.  Correlation does not confirm causality, but the two do seem intrinsically linked.

From the U.S. Department of Energy:

U.S. Energy Sources by Sector

This is a useful chart.  95% of our petroleum use last year was for transportation.  The other energy sources, primarily domestic, are predominantly used in stationary power systems.  The information reinforces the idea that the only way to significantly reduce our dependence on foreign oil sources (roughly 65% of the petroleum we use is imported) is to reduce the use of petroleum in the transportation sector, through alternative energy sources for transportation, through higher fuel economy of vehicles, and/or a reduction in the transportation sector (driving less).

A couple of graphs from the 2008 BP Statistical Review of World Energy provide a concise explanation of the problem.

Here’s where the oil is:

World Proved Oil Reserves, 2007

Here’s where the oil in consumed:

Worldwide Oil Consumption, 2007

That pretty much sums up the problem.

Fuel Economy Standards

Given that 95% of our oil consumption is incurred by transportation, the graph on the left (courtesy of the New York Times) might indicate a large source of the problem.

Just for grins, I dumped the daily ANS (Alaska North Slope) west coast crude oil price and production data into a spreadsheet and graphed out the data.  The results are below:

ANS Production & West Coast Price

So while production, which accounts for roughly 12% of domestic production, slowly dropped by about 100,000 barrels/day, the price did not track along with production.  It would appear that small (1%-2%) deviations in production have no correlation on price (Note to Senator McCain - this would indicate that a “drill here, drill now”  program would have little impact on oil prices).

It would appear that production is only loosely coupled to price, and that any correlation is that price has a slight driving effect on production, but that production has little effect on price.

This is only a rough analysis of a small segment of oil production and price, and should be treated carefully.  Oil is, to a great extent, a global commodity and regional analysis is by nature somewhat suspect.  But by parsing the segment to strictly ANS production and price some general ideas can be inferred.

If you look at last summer’s data, ANS production in September dropped by nearly 30% compared to the spring and early summer of 2007.  At the same time, the price of ANS crude dropped slightly but was effectively flat.  The return to full production in the October timeframe was actually accompanied by an increase in price.

With all the talk about opening up the offshore areas to oil drilling, perhaps someone should ask the question - can it be done on the schedule everybody’s talking about?  I’m not talking about whether there is really that much oil there (doubtful), or policy roadblocks (permitting, environmental issues, etc.), but whether it is physically possible to drill and produce oil offshore within a few years.

To drill offshore you need an offshore drill rig.  You can’t just go down to the corner oil rig store and pick one off the shelf.  These rigs are big, complicated, and very expensive.  It takes years (3-10 years depending upon the size, type, and other factors) to design and construct one and get it ready to drill.  So any near future drilling is going to be done by existing rigs.  How many rigs are available?

Worldwide, there are 693 offshore drill rigs, an increase of 25 from a year ago (in other words, the specialized shipyards that build these things are churning them out as fast as they can).  Of the 693 worldwide, 628, or 90.6%, are already under contract.  As of 1 August 2008 there were a grand total of 65 rigs available for drilling. (Data source: Upstream International Oil & Gas Newspaper, original data set from ODS-Petrodata.)

Let’s be really optimistic and assume none of those rigs are going to be drilling in the North Sea, the Barents Sea, off the west coast of Africa, off Sakhalin, offshore Venezuela, or any place else in the world.  And let’s be pie-in-the-sky optimistic and assume that each rig develops two 2,000 bbls/day production wells each of two years.  So in two years we could have 260 new offshore wells producing 520,000 barrels of oil each and every day.  A half million barrels of oil every day is a lot.  Why, it’s almost 5% of what we import each day.

To put it in perspective, under the most optimistic scenario possible, we could physically produce from offshore drilling less than a third of the oil that we import from Mexico.  And we would be producing it at a much higher price.

Anyone who talks about drilling our way out of high oil prices with offshore oil development needs a reality check.

See also the Inverse Square blog post on this subject.  Or here.

Update 1:  Upstream has a neat graphic showing utilization of offshore rigs, reproduced below for the week ending 01 August 08.  The first graph, 250-300 foot jack-ups, is irrelevant to most of the proposed offshore drilling, since all the discussion I’ve seen centers on >500 foot depths.

Offshore Drill Rig Indices, 01 August 2008

The bottom tow graphs, worldwide semi-submersible and floating rigs, tells an interesting tale.  % Utilization is on the right side, and is indicated by the red dotted line.  Notice that it is effectively 100% for the period of July 2005 until the present?  That tells me that in order to get a drill rig to drill offshore on the U.S. continental shelf, you have to pay a significant surcharge to lure an already committed rig away from somewhere else.

Update 2:  From Upstream, 22 August 2008:

US rig count is up eight from last week ending at 1,998, said oil services company Baker Hughes.  Canadian rig count is up 31 from last week to 457.

Of the major oil and gas producing states Texas remained unchanged at 931 while Colorado lost three, ending at 117.

The US offshore rig count is up two from last week ending at 68.

Alaska rigs were down one to 9, California gained six ending at 51 and New Mexico gained two ending at 83.

Louisiana lost three ending at 193 while Oklahoma gained four to 212 and Wyoming lost three ending at 74.