The gift of coal

I was given a bar of ChoCOALate in my stocking this Christmas. Much amusement was had by all. But the growing dependence of the world on coal, is beginning to get a recognition that has been more evident in the denial of it’s long-term role as a base fuel for the last couple of years. And so, in leading up to a pleasant meaning which exists for a gift of coal let me chat a bit more about coal’s future.

Just this past week George Will noted that Cowlitz County in Washington had approved a coal terminal that would allow the shipping of coal from the United States to China. About 5 million tons a year of coal would be moved by train to Longview from either Montana or Wyoming, and then be exported.

So it's a major new development for the region to begin with. And they are talking about a significant amount of coal – more than 5 million tons a year to start with, which is about twice what the Boardman coal-fired power plant burns in a year. And opponents suspect that number could grow.

But I think the biggest attention-getter is what's driving this proposal, which is growing demand for energy in China and other growing Asian countries.

It is anticipated that coal will start to move through the terminal by the end of 2011. However the environmental concerns have already led the State Department of Ecology to become involved, noting:

In October 2010, Ecology suggested Cowlitz County officials expand their greenhouse gas emissions analysis more broadly in their environmental review. The final review did provide additional evaluation, but Ecology believes it did not go far enough in considering greenhouse gas emissions outside the immediate boundaries of the project.

Yet disallowing the terminal will have little if any impact on the Chinese use of coal. Coal is already being exported through Vancouver in Canada, to the tune of some 26 million tons a year. China is increasing the amount that it imports. By selling into that Asian market Australia was able to avoid the recent recession that hit most of the rest of the world, and while it exports coal to China, Japan and India, it is the growth in Chinese orders that have caught attention recently.

And that demand will not diminish in the reasonable future, despite those who cite the Patzek paper on coal’s imminent decline. For, as even “The Atlantic” magazine noted this past month, in talking about clean coal:

But two ideas that underlie the term are taken with complete seriousness by businesses, scientists, and government officials in China and America, and are the basis of the most extensive cooperation now under way between the countries on climate issues. One is that coal can be used in less damaging, more sustainable ways than it is now. The other is that it must be used in those ways, because there is no plausible other way to meet what will be, absent an economic or social cataclysm, the world’s unavoidable energy demands.

For as the article points out

The journalist Robert Bryce (ed - in the book Power Hungry) has drawn on U.S. government figures to show that between 1995 and 2008, “the absolute increase in total electricity produced by coal was about 5.8 times as great as the increase from wind and 823 times as great as the increase from solar”—and this during the dawn of the green-energy era in America. Power generated by the wind and sun increased significantly in America last year; but power generated by coal increased more than seven times as much. . . . . .(he) describes a visit to a single coal mine, the Cardinal Mine in western Kentucky, whose daily output supports three-quarters as much electricity generation as all the solar and wind facilities in the United States combined.

And in China it takes about 21 months to install a new coal-fired power plant. To supply those power stations they are seeking additional suppliers of coal from around the world.

Arch Coal has just bought the lease to 587 million tons of coal in the Otter Creek reserve in Montana. The company already owned rights to 731 million tons , and it is suggested that the deposits will be mined at the rate of around 22 million tons a year, although mining may not begin for five years.

In the meanwhile, even if the folks in Washington don’t want the terminal, CN would be happy to ship it through terminals at Vancouver and Prince Rupert. Trains take 45 hours from the mines in BC to Ridley at Prince Rupert, and 70 hours to Vancouver, while they take 55 hours from Alberta. It then takes 2 weeks for the ships to get to Tianjin, Shanghai, Quingdao, Guangzhou or Hong Kong. (Give or take a day, and assuming an average speed of 13.5 knots).


Getting coal out of Montana would require improved rail linkages, but one 35-mile link has already been installed to allow the Signal Peak Mine to be developed in the short term, raising Montana production from the 45 million tons produced in 2008. Plans to increase Montana production include a new line known as the Tongue River Railroad which would connect into the Miles City BNSF line that goes up to Glendive, whence it could easily move on into Canada, if it could not move west to Washington.

Planned Railroad relative to mine development

It has taken since 1983 to get planning for the railroad extension this far. And it is still being protested.

Even without the Montana production and even if the Australian mine production is constrained by transient floods, there are lots of other sources that the Chinese could use. These include Mozambique, where plans are moving ahead to increase local mine production up to 20 million tons a year from an estimated 9 billion ton deposit. There are both Chinese and Indian investors in this project, which will occur as the Minas Moatize mine also expands production up to 11 mt/year. Mine development will require improved railroad and port facilities, but it is likely that these can be implemented more rapidly in Africa than they can, presently, in the United States.

The point of which is that there are many places that China and Asia can purchase coal from. There are several places along the Western seaboard from which American coal can be shipped, and large deposits that can be mined to supply that coal. It may even come from those resources that are, in “peer reviewed” papers, considered to be insignificant. But it will get to China, and it will be used to sustain and grow that economy.

With which thought I wish you all a Happy New Year. In my youth the first to come through the door after midnight was to bring in some shortbread or black bun, a couple of pennies, and a piece of coal – and the “first foot” was then rewarded with a tot of, what we called “tea without milk or sugar.” (Good Scottish whisky). The coal was for a wish of enough fuel to keep you warm and fed through the year, the shortbread/black bun represented that food, and the money was for prosperity. Virtually therefore, let me offer you those gifts for this year, and for the years to come.

Cornucopia or Malthusia - a reply to John Tierney

Five years ago John Tierney agreed on a bet with Matt Simmons that by this year the average price of crude oil would average $200 a barrel. The bet is now due, although, sadly, in the interim Matt has passed away. And Mr Tierney has just posted (h/t Leanan) his comment upon winning the bet. While recognizing the impact of the recession on oil prices, after their rise to $147 in the intervening years, he points out that this year crude averaged $80. This he feels justifies the position of the Cornucopian approach to life, rather than the Malthusian.

Would that he were right! In his article he cites oil from new fields coming ashore from fields off Africa and Brazil, and increased production from the oil sands of Canada and the United States, as promising a maintenance of this Cornucopian era into the future. And he uses a historic parallel to show how in an earlier time Julian Simon won a similar bet against Paul Ehrlich, John Holdren and John Harte over the price of a basket of 5 metals.

Admittedly he is currently in good company, since the EIA is not looking for the price of crude to rise above $100 a barrel for another six years, and the IEA recently posted in their December Oil Market Report that global production increased from both OPEC (up 45 kbd) and non-OPEC (up 355 kbd) sources in November. It sees that production will continue to increase through 2011, meeting an increase in demand to 88.8 mbd. 0.5 mbd of that will come from an increase in NGL from OPEC, rising to 5.8 mbd.

Art Berman has just explained some of his concerns with the optimistic projections of the EIA Annual Energy Outlook and I agree with his line of argument. But let me take a slightly different tack in disagreeing with the Cornucopian position.

And it is true that oil companies are now gearing up for a much greater level of investment in this next year than in the recent past. The WSJ quotes a Barclay’s Capital report that levels will reach $490 billion, up 11% on last year. It also notes that the price rises of 2008 led to a boom in deepwater rig construction, and the 25 built in 2010 will be joined by 35 next year. All of which allows the Journal to end with a quote that “Higher investment now will mean lower prices than they would otherwise be in the future.” (Well yes, but . . . . ) But the reality is that the levels of investment that will be required to sustain current levels of production are likely to exceed these numbers, and we are in a time when greater prospecting will likely only lead to a diminished return. Not that we don’t need that investment.

So how does one address this issue. Well Let’s just go back to that original bet by Simon against Ehrlich et al on the price of metals. The original bet was as follows:

Ehrlich and his colleagues picked five metals that they thought would undergo big price rises: chromium, copper, nickel, tin, and tungsten. Then, on paper, they bought $200 worth of each, for a total bet of $1,000, using the prices on September 29, 1980, as an index. They designated September 29, 1990, 10 years hence, as the payoff date. If the inflation-adjusted prices of the various metals rose in the interim, Simon would pay Ehrlich the combined difference; if the prices fell, Ehrlich et alia would pay Simon.

Then they sat back and waited.

Between 1980 and 1990, the world's population grew by more than 800 million, the largest increase in one decade in all of history. But by September 1990, without a single exception, the price of each of Ehrlich's selected metals had fallen, and in some cases had dropped through the floor. Chrome, which had sold for $3.90 a pound in 1980, was down to $3.70 in 1990. Tin, which was $8.72 a pound in 1980, was down to $3.88 a decade later.
Which is how it came to pass that in October 1990, Paul Ehrlich mailed Julian Simon a check for $576.07.

Just out of curiosity I went to Infomine and looked at the price of those metals over the past 10 years (though they only plot chromium and tungsten prices for five). The plots for the 5 metals follow, and to make the calculations simple I have rounded the metal values a little.

Chromium:

$200 in 2000 would have bought 66.7 lbs (it was $3), and in 2005 would have bought 160 lbs of chrome, which would now be worth $425 roughly. Over the 10-year interval however, buying $200 of chromium would have cost you $23, not counting inflation.

Copper:

However, when we look at copper, that $200 would have bought 250 lb of copper in 2000, and over the decade that purchase has gained $862, roughly.

Nickel:

A similar situation applies to nickel, where $200 would have bought about 66.7 lbs of nickel in 2000, and that investment would have gained $533 over the 10 years.

Tin:

The same is also true for tin, where $200 would have bought 91 lb of tin in 2000, and that would sell today for about $1,090; the investment thus making $890 over the decade.

Tungsten:

$200 would have bought 6.25 lb of tungsten in 2005, which would now be worth $265 roughly. It has been difficult to find the price of tungsten in 2000, although the price is reported to have trebled from that pre-2004, suggesting that it was around $14 back then. That would give a purchase of some 14 lb, which would now be worth around $600.

So the $1,000 investment from 2000 would now be worth (in 2010 dollars) $177+$1,062+$733+$1090+$600 = $3,663

Using the Inflation Calculator there has been 27% inflation since 2000, so that the $1,000 would now be worth $1,270. The price of the metals has thus roughly trebled over the time period.

I have not been able to find an accurate value for tungsten in 2000, though I know that the price went up significantly in 2003 when the only mine in the North Americas (the Cantung mine in Canada) closed. It is now re-opening. Most of the world’s tungsten now comes from China.

This reality suggests the underlying longer-term truth to the supply situation for materials that are extracted from the earth. There is only a finite amount there, and while it is possible, due to changing economic circumstance, that a Cornucopian viewpoint might for a while appear true, the growing demand for product, as countries, particularly those in Asia, aspire to Western levels of consumption, will rapidly emphasize the Malthusian long-term condition. (Although cherry-picking specific dates may allow one to transiently make the alternate case).

One has only to consider what is happening to gold and silver, not to mention the rare earth minerals.

Matt may have been a little early in his prediction on $200 oil, but I would be very surprised if we did not see a bit more than $100 within the year. The impact that a price rise above this level will have on the global economy makes it difficult to predict what will happen after that, but we could easily see $150 a barrel by 2015, if the economy can sustain it.

OGPSS - The trade in LNG

Just before the Christmas break the United Kingdom was going through some concerns over natural gas supply. Stored gas levels were falling and the National Grid posted a “Gas Balancing Alert” for only the second time since they were instituted. But there is no more urgent talk of such a problem – what happened?

Well the answer is that rescue, in the form of Liquefied Natural Gas (LNG) tankers came trundling over the horizon. Just this week the UK opened an expansion of the terminal at the Island of Grains that can now accommodate larger tankers, at the rate of 5 a week. LNG from the tankers to this terminal can now supply up to 20% of the national need for gas. But that is a little late for the past crisis (due to scheduling problems the first tanker won’t dock until next week) so where did the LNG come from, and where did it go ashore?

LNG tankers arriving at the Island of Grains and at the LNG terminals at Dragon and South Hook fed additional supplies into the grid.

Flows of LNG were at a total 100 million cu m/d Tuesday after South Hook ramped up 10 million cu m/d to 55 million cu m/d, Dragon was at 15 million cu m/d and Isle of Grain contributed 30 million cu m/d to the system. That is a total increase of 25 million cu m/d on levels Monday.

LNG is also going to be backed up by fresh deliveries in the next week, with UK port data showing three fresh LNG cargoes expected to berth at South Hook from Qatar in the next week, including the Umm Al Amad expected sometime Tuesday, the Mozah on December 23 and the Aamira on Boxing Day.

(The UK used 468 million cu.m. on Monday Dec 20th).

There is a growing global trade in LNG, and while most of this is committed to long-term contracts there is sufficient flexibility in the system so that when, unexpectedly, a nation may run short or a strike close a port, a tanker may be diverted. The South Hook terminal is 67.5% owned by Qatar Petroleum, and is part of a supply net that takes LNG from the Qatargas 2 train, and sends it to the Welsh terminal where it is re-gasified and fed into the National Grid. Dragon, which is also at Milford Haven, is a smaller terminal, and came on line in August 2009. The term “train” is used to describe a single processing line that produces LNG within an overall plant. Thus, for example, when BP expands its facility in Indonesia, the new plant will be called Train 2, to distinguish it from the existing line, which is train 1.

LNG tanker at the Dragon terminal

Once natural gas is produced from a well it must first be processed, and the non-gas liquids (NGLs) as well as water, carbon dioxide, and other contaminants removed so that a dry commercial gas can be sent on. Where the customer is not easily served by a pipeline (such as the case with gas from Qatar being supplied to the UK), the only viable option is to send the gas by ship. Given, however, that gas in its natural state is of low density, it is most practical to cool the gas down to the point where it liquefies. By lowering the temperature to -260 degF the gas turns into a liquid, and occupies 1/610th of the volume. This makes it much easier to store and transport, though it requires that the liquid be kept at that low temperature for the duration of the voyage.

Because the process involves three steps, liquefying the gas, transporting it in special tankers, and then feeding it through a re-gasification plant into a distribution network, the investment in each requires some assurance of a pre-existing market and agreement between the parties before the investments are made. Thus, for example, NTPC in India is now negotiating with Qatar on the supply of LNG in the future as insurance that, when a pipeline is laid from the re-gasification plant at Kochi to power plants at Kayamkulum, that a supply will be available for it. As with the Welsh plant, this can, to a degree, be assured by having Qatar as one of the partners in the project.

The parties likely agree, when making such a deal, to a fixed-price over a considerable time frame. South Korea, for example, is paying roughly $10 per kcf, somewhat above the current rate, but it will have that price for 20-years. Such an agreement may, however, make it difficult for the buyer to initially find customers in the years when that is a high price, as CNOOC found.

Qatar is the largest producer of LNG, having just announced a capacity for delivering 77 million tonnes of the liquid a year, which it currently delivers to 23 countries. This trade has grown from nothing to its current level in 14 years, with production centered around the port of Ras Laffan. (A tonne of LNG converts into 1,460 cu m of NG, or 51,600 cu. ft).

There are seven separate plants (trains) at Ras Laffan with the last having come on stream last February.

Ras Laffan 3 Train 7 is the fourth 7.8 million tons per year LNG plant brought online by Qatar Petroleum and ExxonMobil joint ventures within the past 12 months. It matches the capacity of Ras Laffan 3 Train 6, one of the largest operating LNG production facilities in the world, inaugurated in October 2009. These mega facilities have sufficient scale to competitively reach markets around the globe. Qatar's giant North Field, which is estimated to contain in excess of 900 trillion cubic feet of natural gas, will supply both trains.

Once the gas is liquefied it is transferred to one of a fleet of ships. The earlier ones had the characteristic spheres on board, as shown above, and, for example, Train 1 at Qatar uses a fleet of 10 of these to carry LNG to Japan, with a round trip taking a month. The more recent fleet is 80% larger and more efficient, this 32-vessel fleet carries LNG from Qatar trains 2, 3 and 4.

While there has been a growing market for LNG around the world, and re-gasification plants, such as those in Wales, are being developed in many countries (note the 23 countries that are customers to Qatar) the availability of LNG, with new facilities being planned in countries such as Australia likely means that there will be a continued relatively cheap supply available for a number of years. The consequences to the profitability of domestic production, such as shale gas in the USA, may become more questionable as a result.

The Idaho combined temperatures

There was a blizzard, so I gather, outside our hotel in Portsmouth, NH last night. But we went to bed after driving in as the snow fell lightly, and by the time we left this morning the lot was plowed, as were the streets and highways. It was only when we had to guess where the driveway was up to the house (and got it wrong) that the depth of the snowfall became really evident. (It took 45 minutes to get us dug out). Which is a good reminder that it is time to get back to the changes in temperature over the years. And I was looking at the other side of the country, where they also know how to deal with large snow falls.

Idaho has 29 stations in the USHCN, and a quick glance at the distribution suggests that there are more stations in the southern half of the state, than vice versa.

Idaho weather station locations (USHCN)

Downloading the data, as previously, into a spreadsheet, and noting that indeed Idaho is a relatively elevated state, I turn next to the GISS data, and there are, according to Chiefio, two GISS stations now being used in Idaho, at Pocatello, and at Boise. Pocatello just has data since 1947. A quick check on the GISS site says that the next station is the one at Aberdeen, which is 19 km away, so this is the right one.

Pocatello Municipal Temperatures

.Boise, on the other hand, has a full set of data from 1880 on.

Boise ID GISS station temperatures.

Interestingly it also shows that 1934 was a lot hotter than now. Incidentally there has been some discussion at both Climate Audit, and WUWT relative to the adjustments that GISS make to their data. You have to dig deep into the comments at the WUWT story to get the explanation as to why GISS values for the years keep changing (Eric Smith comments at 9:42 and 9:55 pm and then at 10:09 am on Dec 26th) The latter points to a post wherein Eric Smith (Chiefio) shows how data manipulation can keep temperatures rising, after a record temperature has been set and not broken). As part of that discussion, there is the comment that GISS is tending to marry a short-lived station (post 1930’s) with a longer one in order to emphasize the recent rising temperatures which are more evident with the short term station than the longer term. We saw this pattern in Oregon, and here it is again.

Turning back to this little study, after downloading the temperature records and then going through the locations to find populations, I have to use Google Earth to find Arrowrock and note that it is on the side of a dam:

Arrowrock station by a dam.

So I give this a population of 100 – though that is not strongly defendable. Yet looking at earlier plots of population, the dam sites seem to lie consistently above the line, suggesting it is equivalent to a larger population than that picked.

Bern also needs me to go look on Google Earth since it is too small for citi-data (which seems to only related to places at a level of more than 100 folk). There are a couple of dozen houses that are close, so again I’ll use 100 as the population.

Dworshak Reservoir has 305 according to a reference though again too small for citi-data.

Fenn similarly, where a site gives a population of 40.

Lifton has about 6 houses, and what may be a boat dock, and some apartments (via Google Earth – not much else) so I put down a population of 50.

Porthill, which had a population of 126 in the 2000 census, now has no-one living there. But since someone is reading the numbers I will put down 1. (The numbers from citi-data –see, for example, Priest River are from 2009.

In regard to the geography of Idaho the state is 475 miles long (N-S) and 305 miles wide. The Longitude runs from 111 deg W to 117W, and from 42N to 49 N. The highest point is 12,662 ft, (3860 m), with a mean elevation of 5,000 ft (1,524 m) , though the lowest point in the state is at 710 ft (216 m). The average station is at 1,087 m (including the GISS stations). There are 6 USHCN stations above average elevation, the GISS stations are not.

So how do the temperatures of the state compare? Starting with the difference between the GISS stations and the homogenized USHCN, the average difference, over the century, is that the GISS stations are showing a temperature 4.42 degF hotter than the average for the USHCN.


Difference between the average temperatures recorded by the GISS stations and that of the homogenized average data from the USHCN stations in Idaho. (Note the change when the second GISS station record is added).

Looking at the overall temperature change in the state over the century, and switching to the TOBS data set, since this does away with the adjustments that occur with homogenization.


The temperature rise for the TOBS modified raw data over the period has been at the rate of about 0.8 degF per century, whereas the homogenized data suggests that the rise has been on the order of 1.5 degF over the same period.

Turning to the impact of geography on temperature, the state is more sparsely populated than many in the study vide the amount of extra searching I needed to do to find the populations of some of the hamlets), but let’s see how that plays out.

The effect of latitude:


Against the general trend here there is an increase in temperature as one goes North. Perhaps an artifact of the locations and their elevation?

There is the same contradiction to the overall trend in the country with the plot of Longitude:


The strong correlation with elevation is, however sustained, and may have had influence on the two plots above:


As I noted earlier the stations in Idaho seem to be located in more places with very few residents than I have found in other states.


Yet there remains a good correlation with population across the spread of the plot.

Oh, and yes,

Holiday Break

Gentle Readers,
With many thanks for your kind attention over the last years, I will be taking a break for a short while over the Holidays.

May I wish you and yours the Compliments of the Season, and should you be traveling - travel well and safely.

Be back soon. (Hopefully having learned enough so that next time I can illustrate this myself).

Dave (Heading Out)

OGPSS - pipelines, a help that can be costly

I have written about the limitations in the free flow of oil because of the increasingly heavy and sour nature of the reserves that are now being developed, and the need for suitable refineries to process that oil. I then wrote about how it’s not just oil from oilwells, but also the non-gas-liquids (NGLs) that count toward the total volume of oil that is consumed in the world. There are other constraints to production, and the one that I’m going to talk about today is that of transportation. It seemed appropriate at a time when Chevron has just announced a doubling of the size of the pipeline from the Tengiz field in western Kazakhstan to Novorosslysk on the Black Sea. It will now carry some 1.4 mbd of oil to the port, whence it will be transshipped in tankers.

Transportation is, of course, a major problem for many energy forms, as Leanan caught, the Chinese are already facing problems this winter over the distribution of power.

Most of China's resource production bases, including coal and and oil, are either concentrated in the northern or western provinces, away from the key demand areas located in the southern and eastern region, such as Shanghai and Guangdong.

Any supply shortfall could prompt a surge in import demand as utilities and firms seek alternative fuel supplies to feed their power plants.

And it turns out that they are not the only ones. As the new snowfall wraps over the United Kingdom there are concerns over the distribution of fuel oil.

Downing Street was forced to respond to reports that heating oil might need to be rationed over the winter because of rocketing prices and restricted deliveries, admitting there was a problem moving it around the country.

The energy minister, Charles Hendry, sparked alarm yesterday when he warned the House of Commons that the situation could become "very serious" if there was further snow over the Christmas period.Thousands of public buildings and an estimated 660,000 homes rely on oil for heating and Hendry told MPs some had been told supplies would not be available for four weeks.

All of which serve to emphasize a point that I wanted to make today about how the presence of a pipeline can, but not always, help the situation.

The oil and gas industries flourish largely because of these pipelines, which carry liquids easily over long distances. Perhaps the most famous is the pipeline that carries oil from the North Slope to Valdez. It has survived the varying Alaskan weather conditions, passing over permafrost and rivers, or being buried, depending on the geology. It was the only viable way to effectively develop that reserve.

Alaskan pipeline just North of Fairbanks. Note the radiators on the support legs. These disperse the heat from the pipe (and the oil) which keep the permafrost, in which the support legs sit, from melting. The 48-inch line was sized to carry 2.1 mbd of oil. Today it only carries around 660,000 bd.

Pipelines don’t just allow reserves to be extracted, consider the Rockies Express Pipeline that is bringing natural gas from Colorado through the 1,679 miles to Ohio. Before it was installed Colorado would have a surplus of natural gas in the winter, while the North East had a shortage. To a degree (Caribou Maine being still some distance from Ohio) that has now been ameliorated.

The pipeline route (Kinder Morgan )

Pipelines need to be sized for the volumes that flow. In order that the oil/gas flow down the pipe the fluid is pumped into the line at pressure, and at stages along the pipe, as the pressure is “used up” on overcoming friction from the pipe walls, there are booster stations that raise the pressure back to the driving pressure, to keep it moving. (And yes these use some of the fuel, particularly if it is gas, as a power source).

One of the problems with running the pipe under that pressure is that if there is any corrosion or damage to the pipe then the pressure may have to be lowered to stop the pipe from bursting. Since the flow velocity is a function of the square root of this driving pressure, then as the pressure drops so does the volume pumped.

As a result inspection to make sure there is little or no corrosion should be a regular feature of pipeline maintenance. Given that the pipe can run for miles above or below the surface, external inspection can be difficult, and, instead companies will run “pigs” down the line. (The name comes from the “squeal” as they move) These are put into the pipe at the “top” end and pumped down with the oil. Instruments and sensors within the central compartment can monitor conditions as the pig moves. Pigs are also fitted with wipers the ensure that deposits from the fluid don’t build up along the pipe and cause problems.

Example pig used in the Alaskan pipeline – see the wipers and note the central compartment within the pig.

It is difficult to stop all corrosion, and over time segments of the pipe may need to be replaced because of damage that can build up in the normal course of operations. If inspections are not regular, then, as BP found in 2006, corrosion can lead to a leak, and big problems.

Unfortunately pipelines are not just prone to mechanical problems. Their presence is hard to hide, and thus, become targets for theft. Whether in Mexico this weekend, or Nigeria almost every day, theft by physically extracting fuel from pipelines can be a very dangerous game, with explosions and loss of life a not-infrequent result.

And that is just the small scale operations. On a larger scale the risk can be a lot less. Remember that Western Europe is becoming increasingly dependent on Russian natural gas for supplies, particularly in the winter months. That natural gas travels between the two passing down a pipeline through Ukraine. The financial woes of that country meant that it did not always pay its gas bill, and, usually in January, this led to confrontations between Russia and Ukraine, with Western Europe the frequent loser. To overcome this dependence Russia is now putting in place two smaller pipelines that will circumvent Ukraine to the North (Nordstream) and the South.

One of the key players in that game was Turkmenistan, which supplied its natural gas through pipelines that only went through Russia to their customers. Russia for years was able to dictate the price that it paid Turkmenistan, often considerably less than it was getting from Europe. But since it was the only game in town . . . .

That recently changed, however, with the construction of a pipeline from Turkmenistan to China and this broke the monopoly that Russia held over the sale of Turkmen gas. The pipeline is now being upgraded and the flow increased to 1.25 billion cu ft/day, four times the volume that flowed, on average, last year. The pipeline is 4,350 miles long. Ultimately the flow will be three times that size – about the volume that Turkmenistan used to sell to Russia. (The last reference has the picture of what may be the one Soviet attempt to extinguish a burning gas fire with a nuclear device that didn’t work).

The Russians haven’t forgotten the benefits that come from owning the pipelines and the control that this gives over the producers. BP learned that lesson the hard way. Gazprom is the Russian company that owns the pipelines (and on a slow news day I could always find a story by seeing what new machinations had been revealed in a Google seach for Gazprom). By controlling the pipelines they could dictate what flowed when. As an example let me remind you of the situation that BP faced in developing the Kovykta gas field back in 2007. The deal was that after BP developed the field, they had to produce 9 billion cubic meters (bcm) per year, as the license stipulated. But local consumers could only handle a small fraction of this, and Gazprom, who owned the only pipeline in town, was only willing to allow a flow of 1.7 bcm. Oops! You guessed it, BO was held liable for not meeting the terms of the license and . . . . .

You will note that Gazprom has been quite efficient at getting control of a large portion of the pipelines and (as a result) the distribution networks across Europe.

That story brings to mind another caveat, that illustrates the bind that pipeline owners can impose on their clients. Bear in mind that these pipelines are not cheap, and while they can be installed relatively rapidly, they have to be paid for. Thus, before they are installed the owners require long-term commitments from both the seller at one end and the vendor at the other. The Rockies Express has such commitments.

REX is a joint venture of KMP (we own 50 percent and operate the pipeline), Sempra Pipelines and Storage and ConocoPhillips. Long-term, binding firm commitments have been secured for virtually all of the pipeline's capacity. The pipeline is enabling producers to deliver gas from the Rocky Mountains eastward and is helping to ensure that there will be adequate supplies of natural gas to meet growing demand in the Midwest and eastern parts of the country.

There is an underlying point here that is sometimes missed when these projects are discussed, and that is that the agreements between all parties will usually establish a price for the product, at the time that the contracts are signed, that run well into the future. Those prices do not reflect the current market price of the fuel. It is a point that often gets overlooked in discussions over fuel distribution. But many of the ways in which fuel is shipped require considerable investments not only for the production, but also for the transportation, and then for the distribution. Thus the need for commitment and guarantees before the process of construction begins. (This has just been evident in the wait in starting new coal mines in Australia, for example, until long-term contracts with China had been signed.)

However, if the pipeline owner then changes the rules, there is not a whole lot that the other two partners can do – as a whole list of countries who have been squeezed by Russia would be glad to remind you.

But it is not just over Russia that the world should have a concern. One should not forget the new pipelines that are being constructed across Asia. Whether the Chinese pipeline from Turkmenistan, or the TAPI pipeline from Turkmenistan to India, these mark a switch in the destiny of future fuel production. It is a future that means that a considerable volume of the worlds fuel may no longer be available to the West. And where that fuel is natural gas, and the nations of Europe are building gas-fired power plants to back-up wind and other renewable sources, then if the gas isn’t there . . . . .

No problem, you say, old HO is being his usual alarmist self. Well you might want to note how many times this winter there is a “Gas Balancing Alert” action in the UK. Rune Likvern has already highlighted the start of a possible problem as stocks were drawn down at the start of the winter and it has not got any better. The first Alert has been issued for this season.

On Monday the National Grid issued a gas balancing alert (GBA) for only the second time, asking power suppliers to use less gas as more was sourced overseas. Extra gas - including supplies from Belgium and Norway - was necessary to meet rising demand after a 30% rise on normal seasonal use during the cold snap.

This is only the second such alert, the first coming last January.

Further information can be found on the National Grid Website. The normal daily usage at this time of year, according to that site, is 364 million scm (standard cubic meters). The trigger for a GBA is 452 mscm, and tomorrow’s demand is forecast at 463 mscm. Interruptions seem most likely to occur in the North.

Oh, and just to give you a better sense of the scale of some of these pipes - here is me beside the one in Alaska.

Oregon Combined Temperatures

Having previously looked at California and Washington, examining the temperature behavior in Oregon will complete the West Coast sweep (outside of Alaska and Hawaii). This is another state with a lot of stations, in this case, the USHCN lists 40, so the first thing is to get that data into a spreadsheet. And looking at the USHCN site, it dawns on me that I could enlarge the map to show where the stations are. So this is the map.

Location of the USHCN stations in Oregon.

Chiefio’s List gives two GISS stations are at Medford and Pendleton, though when I click on the Oregon segment of the GISS station selector map it takes me to Mexico – ah, well. Type in the names- well first shot gets no Medford. Try Pendleton, and egads, a full set of data for once. And the high temperature was in 1934.

GISS data for Pendleton

So let’s download that data first, and then go look for Medford. Turns out it is near Klamath Falls, so I type that in, and GISS finds it, and then I look for adjacent stations, and lo, there is Medford. Only data since 1947, but still . . .

GISS record for Medford.

Looking at the state geography, Oregon runs from 116.75W to 124.5W, and from 42N to 46.25N. It is 360 miles long and 261 miles wide. The average elevation is 3,300 ft (1,005 m) with Mt Hood being the high point at 3,425 m. (The average station elevation is 550 m)

So what does the data tell us for the temperatures of the state. Interestingly the GISS data is a consistent 4 deg higher than the USHCN over the entire recorded period.


As far as the temperature has changed over the years (using TOBS data) there has been a slight increase, at the rate of 0.6 deg/century (the homogenized data shows an increase of 1.3 deg/century).


Turning to the geographical effects, these are for latitude:


Interestingly this is showing an increase in temperature, albeit not significant, with latitude, which is contrary to just about every other state.

On the other hand the change with longitude is explicable in that the higher elevations are to the East and thus as the land goes west it lowers, and thus gets warmer.


This is borne out by the effect of elevation:


And this leaves population. There are a couple of places that were hard to find numbers for, one being a power station, where I put in a nominal 100.


And of course we should not forget:

Resources, Reserves - the EIA - coal gas and oil for the future.

One of the significant issues that can get folk argumentative, is the role that price plays in determining whether a fuel source still buried in the ground is called a resource or a reserve. For example I have exchanged opinions several times with David Rutledge on his view of the declining reserve base for coal. Most recently he has written in The Oil Drum pointing to the latest paper he has written on the topic, which is available at his website. Part of my rebuttal comment inferred that as the price of the product increased (likely through the lack of other reserves to be able to sustain the energy supply need of countries around the world) so coal will be recognized more and more as a reserve, which will be used, rather than a resource that will not.

The argument is also made that as price goes up the viability of resources that would cost too much to produce would change a significant volume of those resources back into reserves. That holds true for crude oil, in just the same way as for coal, except that with so much of the world’s cheap crude having already been produced, the availability of the resource volume that will convert over as price rises is not necessarily that great. I bring this up because in this week’s TWIP, from the EIA, they address this problem in regard to how much increasing the price of crude in 2009 increased the amount of crude (including condensate). Their answer was 9% for crude and 11% for natural gas.
(And as 1 of 2 UPDATES to the story, Russia has stated - whether because of exploration or increased value is not clear - but that it fully replaced its oil and gas reserves this year (h/t Leanan).)

Gain in Oil reserves (EIA)

Gain in Natural gas reserves (EIA)

The gas gain, as the EIA note, occurred at a time where gas prices were suffering from the additional volumes made available from the shale deposits of the country.

Domestic production of crude has stabilized at around 5.6 mbd, while imports are running at around 8.5 mbd, and refinery input within the US continues to rise. Gasoline production continues to mirror, roughly, last year at this time, while demand is running around 300,000 bd more than last year. This time last year distillate production was reducing, this year it continues to increase, although demand, which dropped precipitately for the last month, is now stabilizing at about last year’s level. And ethanol production continues to creep upward.

Biodiesel production is a little harder number to come by, there is a plot through 2008:

Biodiesel production (National Biodiesel Board)

There are reported to be `173 companies engaged in producing biodiesel (from a number of sources and in a number of ways). If all of them ran at full production it would generate an average of around 175,000 bd, which is not yet much of a significant figure. Additional companies planning to get into production might raise production by 15% but this remains still only a small fraction of what is going to be needed.

UPDATE: I have been pointed to the note earlier this year that the EPA had slashed the cellulosic ethanol mandate for next year:

Cellulosic biofuel was 250 million gallons, now 6.5-25.5 million gallons
Biomass-based diesel was 800 million gallons, and stays there
Advanced biofuel was 1.35 billion gallons, and stays there. . . . . .

“We first considered whether it appears likely that the required biomass-based diesel volume of 0.8 billion gallons can be met with existing biodiesel production capacity in 2011…we believe that the 0.8 billion gallon standard can indeed be met…Of the remaining 0.15 bill gallons, up to 0.026 bill gallons would be met with the proposed volume of cellulosic biofuel. Based on our analysis as described in Section II.C, there may be sufficient volumes of other advanced biofuels, such as imported sugarcane ethanol, additional biodiesel, or renewable diesel, such that the standard for advanced biofuel could remain at the statutory level of 1.35 billion gallons.”

(end of update)

Which brings me back to my original point which is that a change in the perceived selling price of the product (I say that because of the gas situation) has led to significant investment that has raised the reserves of a commodity that is recognized to be getting into short supply.

However, to put this in perspective, the gain in oil reserves was 3.69 billion barrels. The United States uses around (rough number) 20 mbd of oil, or 7.3 billion barrels a year. The gain in reserves will thus provide the equivalent of a 6 months supply, and while production will be spread over a number of years, it really doesn’t change the arithmetic that much. What is forgotten in the discussion, however, is that the equivalent change in reserve size is also occurring in other parts of the world. And while many of these places are, like the United States, in an era where their fields are now depleting, the increased value of the product is likely to slow that decline somewhat.

Coal, which is also where the discussion started, is in an even more robust situation. Coal price is still driven by the cheapest producer to the world market. It is not practical to consider opening a new mine in, for example, Montana, if the power companies around the country are already being adequately served by local deposits and by trains from the Powder River Basin. No-one will put up the investment capital to open new mines without a market, and with the current transient switch to natural gas, that incentive does not exist in the United States.

However the rest of the world is somewhat different. Bear in mind that the prices that oil and gas will reach, in the non-too-distant future, will be significantly above what many nations can pay. If they have indigenous sources of energy – vide coal – and enough of it then they will start building coal-fired power stations. They don’t have to play games with taxing one form of energy to encourage another, they need the cheapest possible source of power. And at the moment we know what that is!

And just to emphasise that, here is the most recent projection for future demand from the EIA.


I will forgo a comment on the assumption at the top of the plot.

Afghan oil, and gold, and iron

I noted today that the Afghan government is beginning to pin some hopes on oilfield development as a way of helping generate some desperately needed cash. It was just last August that a field containing up to 1.8 billion barrels of oil was reported. There has been exploration and hopes of significant production in Afghanistan since 1937 but there has been little significant production as yet. Prior to the Soviet invasion in 1979 it had been estimated that the country had 100 million barrels of oil and a refinery was planned, but cancelled by the resulting conflict. The Angot field had been identified, and some 14 wells drilled into it, without much production. In those years much of the Afghan energy production was in natural gas, that was shipped to the Soviet gas grid, via Uzbekistan. The conflict and guerrilla activity in the region lowered production, and when the Soviets left many of the wells were capped.

An attempt to start the oil production process over at the beginning of this year was not successful, with only a single, rejected, bid being received. A Norwegian evaluation of the situation in June suggested that it was too early for a decision.

Balancing the notable achievements that have come in place through Norwegian facilitation and support for the Government of Afghanistan with the range of risks identified in this report, and not least the two central conflict issues identified in the literature review, Norad is advised to consider the following: Await further engagement on policy matters relating to implementation of the Hydrocarbons Law and a new (if materializing) Hydrocarbons bidding round until there is further clarity as to how the Government of Afghanistan aims to develop and utilize these resources and to what extent major external donors support such policies”.

But by August, when the new discovery was made, a rig had been fielded in the Angot field in the Sar-i-Pol (Sar-e-Pul) region in the North to begin a production stream. It is that field that is now being brought on line, looking to production from both new wells and some of the existing older ones that will be refurbished. Production will only be on the order of 800 bbl/day but for a country where the United States spends $250 million a year providing diesel for the Afghan forces, any start is welcome. The oil will be extracted by the Afghan government and then sold at $80 a barrel, and is being marketed to an Afghan group, Ghazanfar Group. The company is one of the largest private companies in the country, and made $475 million in gross earnings from its petroleum business in 2008 (up from $2 million when it got into that business in 1998).

And just as the “black gold” of the country is starting to be developed, so also is the real yellow stuff. Plans were also announced for a gold mine to be opened.

About 10 investors - most of them from the United States and Britain - are investing an estimated $50 million in the gold project in Dushi district of Baghlan province, about 84 miles (135 kilometers) northwest of Kabul, Wahidullah Shahrani, Afghanistan's minister of mines, told the Associated Press. The only other gold mine in Afghanistan is in neighboring Takhar province.

There has been considerable talk of the mineral wealth that is part of the Afghan geology. These developments, and preliminary discussions on the mining of the largest iron ore deposit in Asia, that at Hajigak, reputed to have 1.8 billion tons of a 62% purity, are an indication that there can be progress in moving the country into a more prosperous future.

It is interesting to note, however, that in the case of the iron, as is the case with some of the oil in Iraq, it is China and India that are looking to develop the industries, and thereafter likely to consume the product. It Iraq they are already hard at work. The Chinese are willing to go into countries such as Iraq, and Afghanistan, as well as Sudan, which now sends more than 60% of its oil output to China. They face the difficulties of operating in countries under wartime conditions, and yet the benefits that can accrue will assure them of needed supplies in the years ahead.

The new fields that are being developed in Afghanistan lie in the north of country and the oil transitions to gas as the reservoirs approach the Turkmenistan border and the much richer gas deposits that lies north of the Amu Darya River. The new developments are also to the East of the planned route for the gas and oil pipelines that have been discussed, for many years, as a way of bringing needed energy to India and Pakistan.

Planned Afghan pipeline ( derived from one in The Canadian )

And while the pipeline may remain more a paper exercise, the production of the fuels has begun. But it should not be forgotten that the Chinese have already initiated one pipeline with Turkmenistan and that pipeline is a whole lot closer to these fields, over less disputed ground, than it would be sending the production South.

OGPSS-When oil isn’t crude and gas isn’t gas, the Eagle Ford Shale play

There are two figures that keep cropping up when folk write about the production of oil, one number is the daily flow rate for crude oil, and while the EIA report that the peak production year to date was in 2005, when the world produced 73.72 mbd, the IEA have reported that the peak occurred in 2006. Yet just last week the IEA raised their forecast for next year’s oil demand to 88.8 mbd and there is about 15 mbd difference between the two numbers. So you might ask what causes this, where do these additional liquids come from and what is their future, relative to that of crude alone.

Part of the answer comes from what are known as refinery gains, the fact that when you crack a high-carbon crude into lower carbon products in a refinery then there is a gain in volume. In Oil 101 Morgan gives this processing gain in volume to be around 2.2 mbd. In addition there is the rising level of bio-fuel production, about 900,000 bd of ethanol in the US alone, for example. But the largest volume comes from the liquids associated with the production of natural gas.

These are collectively described as Natural Gas Liquids (NGL) and condensate. Simplistically, when natural gas comes out of the reservoir it is not always what is referred to as a dry gas, but rather can often contain a number of other constituents in the fluid flow. The NGLs are normally a combination of ethane, butane, isobutene, propane and natural gasoline and are normally combined with other light hydrocarbons that condense out of the fluid flow at the surface, when pressures and temperatures fall from those in the reservoir. These additional fluids are the ones generally called condensates, as a result. (The NGL's need a little pressure to re-liquefy). NGL total volume is about 8 mbd. Now to make life somewhat more complicated both oil and gas can come out of the same well at the same time in a admix that can include all of the above. And that requires that they be separated, but that is a topic for another day or two. Today I want to give an example of the importance of those liquids that lie between crude and natural gas.

These mixtures can be more important, depending on the relative composition of the flows that are then obtained. Consider, for example, the Eagle Ford shale, the new field that is being developed in Texas, where wells that are to be drilled into the gas shale are now touted for their liquids content, rather than for the natural gas that they are more commonly anticipated to produce. When the field was first drilled, back in 2008, the initial well flowed with natural gas production of 7.6 million cf/d and there have been some 944 permits for wells as and of last week.

Wells in the Eagle Ford Shale Texas Railroad Commission

However it is not just the surface location of the wells that has to be considered. And if those of you with more knowledge will forgive the repetition, I need to just give a short paragraph of explanation about where oil and gas originally came from. Very simplistically they come from algae that flourished in the oceans of the time, somewhere between 65 and 500 million years ago. The algae contained some lipids (an oil precursor) as do those of today. As the algae died their bodies fell to the seabed where they accumulated in layers, along with the sediment that collected with them. Over time that nascent rock was buried deeper in the Earth’s crust and as it did the pressure and heat slowly changed the lipids, initially into oil. However if the rock was carried deeper, then the oil was further cooked and became natural gas. The process has been illustrated at the oil and gas geology website where I got this illustration:

Transition from lipids to oil and then gas over time and depth of burial ( Oil and Gas Geology )

As a rough rule of thumb down to 15,000 ft the hydrocarbon is more likely to be oil, (which is thus referred to as the Oil Window) and below that it is more likely to be gas. That is only a rough rule of thumb, and one must remember that over time there has been a lot of uplifting and eroding, so that 15,000 ft isn’t necessarily what it used to be.

And the Eagle Ford shale is a fairly good example of this. If we use the EIA map of the play you can see that in the North, where the reservoir is about 6,000 ft deep the hydrocarbon is oil, while further South, where the deposit is down at around 14,000 ft then the hydrocarbon is dry gas. And in between it is what is known as a wet gas.

Eagle Ford play showing the depths to the reservoir and the nature of the hydrocarbon (EIA )

You will also see that the majority of the wells are in the wet gas/condensate section of the field. As a result, when we look at the amount of the different fluids that have come from the field in the two years of major production to date, we get the following plot. And to make it, I have made the simple assumption that 6,000 cubic ft of natural gas is equivalent to a barrel of oil (which I call the Apache number )

Fluids produced from the Eagle Ford shale (Texas Railroad Commission )

You may note that the condensate from the wells in the wet gas zone have produced around 2.3 million barrels, while there has only been about 1.6 million barrels of crude produced. It is also worth noting that while the natural gas coming from the formation has been twice the equivalent volume of oil, the market for natural gas, at the moment is still down at around $4.6 per kcf, which using the Apache conversion, would give it a price of around $27.60 a barrel of oil equivalent. On the other hand the condensate is a light high quality product, and West Texas Intermediate crude is running at the moment at around $88.30 a barrel. (EIA last Natural Gas Weekly ) You should also remember that these are not the retail price for the products – natural gas in Florida, for example, was given as $10.56 per kcf, while it is around $9.81 in New York (ibid).

The current excess of natural gas over supply, which is likely to continue through at least next year (and which I will discuss in more detail in a number of future posts) will likely keep the price of natural gas down around the $4 figure through most of next year. On the other hand the increasing demand for oil when set against the limited ability of the industry to respond, will likely mean that oil may well move over $100 a barrel.

So now you know why they are drilling in the middle of the play known as the Eagle Ford Shale.