Waterjetting 37c - A Drilling Diversion

I was asked some questions about waterjet drilling of holes the other day, and it is amusing to remember where it all started, more than 30-years ago. My apologies again for the quality of the video, which has been transferred from 16 mm film, to half-inch tape and thence via a DVD to its current form, losing a little in each transition.

Figure 1. The Cygnet Project part 1.

Perhaps one of the more memorable parts of this was that we arrived on site on the Monday, and spent the afternoon setting up. Since there really wasn't that much to the rig we were done quite quickly, and were then faced with an hour before the end of the day. The overall object was to drill a hole 50-ft long, and we had arranged the camera crew to come for the filming on Thursday, so that we could work out all the snags first. But we had a pleasant surprise.

We put our first test nozzle on the lance, and started drilling - it drilled the full length with no problems, we added a second length - same result, and third . . . and then the fourth and within the hour we had achieved the goal for the week. (And run out of drill lengths).

We had the same sort of experience some years later in trials I helped with that were run by the University of Queensland in Australia, although this time we were self-propelling the drill head, so that when we ran out of the outer rigid frame we attached a length of hose, and it kept on drilling, until we had run through that also. Problem was that the drill was then pulling itself forward without any advance rate control, and if it went too fast it did not drill a large enough hole for some of the following structure (we had backward pointing jets for propulsion and hole cleaning).

So somewhere I have a photo of three of us holding the hose back to slow the advance as the drill moved forward, so that it would maintain the 15-cm diameter IIRC. And again we accomplished the goal well before we had expected, and without the need for a lot of sophistication in the design.

Power shortages in India and Pakistan

The recent publication of the EIA review of Shale Gas has caught the world’s attention, and led to the perception that the coming decades may well see natural gas become the dominant fuel. It suffers, however, a couple of disadvantages that, for some countries, make it not always the fuel of choice. India and Pakistan, have serious energy shortages as Tom Whipple recently pointed out.

In Pakistan the electricity is now turned off for 18-20 hours some days in many cities and 20 hours in rural villages. The onset of summer temperatures, shortages of fuel oil for thermal generation and falling water levels have increased the power shortfall to record levels. Without electricity to run the pumps urban water supplies quickly shut down. Without power to run the mills, exports are falling, leaving the country without money to import oil. In short we are seeing a classical downward spiral.

At the same time, in India, the domestic natural gas supply is falling, requiring increased, and more expensive imports that can only be achieved using LNG resources.

There have been discussions for years over the possibility of running gas pipelines from Turkmenistan and Iran down through Pakistan and into India to provide the natural gas needed to help. The TAPI pipeline from Turkmenistan is currently at a stage where it may be moving forward. Pakistan is ready to commit to purchasing gas by this July, but . . .

.

In the four nations’ ministerial meeting last week, both India and Pakistan had agreed to the broader aspects of the gas sales and purchase agreement (GSPA), but crucial things like the price of gas and transit fee are yet to be decided.

At present the Turkmen are expected to demand at least $7 to $7.50 per kcf, which is the price that they are getting from China. And transit fees to get the gas through Afghanistan and Pakistan to India will be added to that. (In context that is about the same price as LNG when it is currently delivered in India, and above the $4.94 to $6.42 price of domestically produced gas).

The current hope is that the pipeline will be started in 2013, with full flow to all three countries by 2016. The pipeline will have to run a thousand miles before it reaches India. And this highlights one of the problems with natural gas. It is harder to deliver than other fuels.

Oil can be put on rail cars, or tankers, as well as being piped, as can coal (though there are very few places that use pipelines to move coal). But natural gas either requires a direct pipeline, or it has to be condensed to liquid form for shipment. When large volumes are involved turning the NG into LNG requires construction of both a condensing plant at the supply end and a re-gasification unit at the customer end. Both require time to build. And one the gas is regenerated, the customer has only a limited capacity for storage, and depends on the flow coming through the delivery pipe to keep power being generated.

Coal at the other extreme used (in my youth) to be delivered to our house from the back of a horse-drawn cart. It was dumped in the street, and we shoveled it into the “coal bin” out of which we then hauled it, a bucket load at a time, into the house, and dumped it on the fire. Logistics were a lot simpler, and we kept at least a couple of weeks supply in reserve in the bin.

Times have changed somewhat, for although shovels may still dig out the coal, they now can load a hundred tons, rather than a few pounds. Rail cars can haul 120 tons apiece in unit trains of 100 cars, and power stations may use 10,000 tons of coal a day to generate 850 MW of baseload power. But the coal is often still dumped in heaps at the power station, to be used when needed. Stations will usually keep 60 to 90 days of supply on hand.

India is aware of these advantages, but has internal problems with developing enough domestic coal supplies for the power that it needs. Coal India has said that it can only deliver 100 million tons against the 330 million ton increase in demand that, over the next five years, that power stations now being built will need.

With domestic coal production floundering amid a sharp upsurge in power capacity addition, over 40,000 MW of new generation capacity could get stranded over years for want of fuel. This is close to 70 per cent of the power capacity slated to come up during the period, most of which is being set up by private developers.

With a current generation capacity of 173,626 MW, this threatens the generation of some 42,000 MW.

There is a catch with using imported coal to meet all the shortfall, because of the construction of the Indian boilers. They blend about 10% of the higher thermal content imported coal with domestic coal but there are technical problems with a higher concentration that limit how high it can be raised, as well as the additional cost factor. However new construction can be built to handle higher concentrations of imported coal, it just costs more – which is expected to be a problem in relatively poor parts of the country.

Seeing this as an opportunity, however, Adani Enterprises, an Indian coal company, has just bought the Abbot Point coal terminal in Australia, after buying coal properties in Queensland last year. Over the next five years they will bring the mines on line and be able to feed up to 50 million tons into the Indian subcontinent. It is not enough, in itself, to meet the shortfall, but it is evidence that firms in India are aware of the problem and are moving to find answers. They will do so, however, in the face of stiff competition from China. And this competition underlines the conclusions that I drew in an earlier post about the unrealistic projections of future coal use by folk such as Tad Patzek and Dave Rutledge.

Unfortunately also this does not solve the immediate problem that India faces with a current shortage of available fuel. Nor does it get Pakistan any closer to finding a short-term solution to power shortages in that country. There comes a certain point where, when warnings go unheeded, the consequences must be suffered, though sadly often not by those who weren’t paying enough attention.

OGPSS - Countries producing over 500 kbd - Malaysia, Australia, Colombia and Ecuador

Over the past few weeks I have been briefly discussing the amount of oil that the major producers of the world generate each year. Starting at the top, with Russia and Saudi Arabia, I have now arrived at the bottom end of the list of countries producing more than 500,000 bd. I am concluding with Malaysia (727 kbd), Australia (586 kbd), Colombia (602 kbd) and Equador (504 kbd). For those interested the list (the EIA top producers in 2008) would have continued with Sudan (480 kbd), Syria (401 kbd), Equatorial Guinea (359 kbd), Vietnam (337 kbd), and Thailand (328 kbd) to cover the countries that produce more than 300 kbd.

But my interest in these countries stems for the need that the world has for significant increased production, and the further that one moves down the list the harder it is to see any country being able to produce an extra 200 kbd say, to provide the additional power that Japan might need to replace the destroyed nuclear reactors, not to mention the 1.4 mbd that has been projected for the growth in demand of the world economy this year, nor the 1.6 mbd that the loss of Libyan production will impose on global supply.

So let us begin by looking at the production from Malaysia, which seems to have hit a plateau in production of crude oil in recent years. Production levels are projected to stay about current levels, slightly below 700 kbd through 2020, with some of that coming from enhanced oil recovery techniques. Malaysia is also the second largest producer of palm oil, at around 300 kbd though a lot of the latter is used in cooking.

Malaysia lies north of Indonesia (covered earlier in the series)

Malaysia (EIA map )
While production is holding relatively steady, consumption within the country is steadily increasing so that, before too long, it is likely that the country will cease to export oil, in a similar fate to that of Indonesia. This despite plans to further develop offshore fields.


Extrapolation of the above lines suggests that Malaysia has hardly any time left until it stops being able to export oil.

Natural gas, however, is another story, with steadily increasing production, to date, being able to out-perform increasing domestic consumption. Thus exports, which ran around 1 TCF in 2009, have continued to grow.


The country exports around 1 TCF of LNG, two-thirds of which went to Japan. With only one of the re-gassifying plants in Japan out of operation, LNG provides a way of meeting some of the current energy shortfall in Japan, and Malaysia is willing to help. Malaysia is also now supplying China with LNG, with flows into Shanghai anticipated to rise to 3 million tons/year next year.

Australia is next on the list and it appears to have passed peak oil production, and as a result exports have dropped from over 500 kbd in 2007, to just above 300 kbd today. The declines in production are expected to continue

"The recent start-up of BHP Billiton's Pyrenees oil field and Apache's Van Gogh field - both situated off Western Australia's north-west coast - will provide a boost in the short-term, however the long-term trend is for production to keep falling," EnergyQuest Chief Executive Officer, Dr Graeme Bethune, said today.

(this from April 2010). Current production is at around 540 kbd, having fallen 40 kbd in 2010.

The decline with a projected drop of 85% in 10 years can be seen from this graph:

Anticipated future Australian production (Geoscience Australia )

At the same time Australian consumption has been steadily rising, and is hovering just below 1 mbd.

Australian oil consumption (Index mundi )

In contrast Australian natural gas reserves are significant. As with Malaysia it has supplied LNG to Japan, starting in 1989 and has just signed a $41 billion contract for a 20-year supply of LNG from the Gorgon field, taking 2.25 million tons of the anticipated 15 million tons (0.75 Tcf) of annual production anticipated from the field, as overall gas production continues to rise.

Current estimates of Australian natural gas reserves are of over 108 Tcf


Colombia (Source EIA )

Colombia sits next to Venezuela, and I referred to some of the interplay between the two countries in an earlier post on Venezuela. Production of oil has fluctuated but has recently been increasing, so that it is now running at 800 kbd, and this is anticipated to increase to 1.2 mbd by 2012. It is thus one of the few countries that might be able to increase supply to the United States as some of the more traditional sources lose production.

Colombia oil statistics (Energy Export Databrowser )

The problems that currently exist relate to the need for additional pipeline capacity to carry the newly developed reserves to a point where they can be exported. Investments in the country from China, among others, support a prediction of further growth to 1.4 mbd by 2014.

As I referred to in the Venezuelan post, some of Colombia’s natural gas has been exported to Venezuela, with the intent that in 2012, as the Colombian reserves start to decline the flow can reverse. Much of the natural gas has been used for improving oil production in the past with the country consuming some 265 Bcf while producing 318 Bcf.

Ecuador (EIA )

And the final country producing more than 500 kbd is Ecuador, although that was in 2008, and by last year production had fallen to 485 kbd. The country shows the more standard shape illustrating the Export Land model with an accelerated decline in exports as consumption rises, even as overall production now falls.

Ecuador oil statistics (Energy Export Databrowser )

It would seem, since Ecuador exports to the United States, that the increase in Colombian production is timely.

In regard to natural gas, perhaps the EIA says it best

Ecuador has relatively small proven natural gas reserves and a limited natural gas market.

The supply that it has is used internally, mainly for electricity generation, while much of that associated with oil is either flared or reinjected to help with production.

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.

Longwall mining with shearers

The development of longwall coal mining took a significant step forward with the development of the armored face conveyor (AFC) and the self-advancing supports of both chock and shield designs that I described last time. Put together they provide two of the three major parts of a modern longwall. The third, and the topic for today is the mining machine itself.

The longwall panel with shields and a mining machine is at D.

In the evolution of longwall, an undercut beneath the face was initially cut out by a man wielding a pick. By the turn of the 19th century this was starting to be replaced by a machine, much like a giant chain saw, that undercut the face to a depth of around 5 – 7 ft. And, while in earlier times the coal was broken from the solid by hewers that used picks to break out the coal to the free face left by the slot, with machine undercutting the bulk of the coal was broken down by single sticks of explosive set into the coal at about 6-ft intervals along the face.

The AFC, as well as carrying the coal away from the face, had two hard bearing surfaces at the top of each pan, which connected together to provide a path along which a machine might move. But what sort of machine was going to be capable of mining the full face of the coal. There were a number of different designs developed, many of which started with the long cutting chain of the coal cutter, and added other blades to it, in order to fully remove the bulk of the coal. I’ll mention only three of them, in passing.

The first idea was simply to mount a cutting post at the turning wheel of the conveyor, deep in the cut, in order to back cut the coal, and move it out of the web. The machine had a number of teething problems and did not prove very effective in underground trials. It was quickly passed by the Meco-Moore Cutter loader which by 1956 had become one of the most popular integrated mining machines in the United Kingdom. It is important for those who talk about the energy required to mine coal to understand how it worked.

This was still at the time that the roof was supported by manually placed props and bars (which can be seen in the background). However the bottom of the coal was first cut with a cutter bar that was 6 ft long. Concurrently the central part of the seam was cut by a second cutter bar, which cut a slot to a depth of 4 ft 6 inches in the coal. A third slot, at the back of the face, was cut using the triangular shaped cutter bar shown in the illustration. Coal has sensibly no strength in tension, because of the cleats and bedding planes that form within it during the process of forming the coal. Thus the web of coal that has been undercut, mid-cut and back-cut will collapse onto the small cross-conveyor, which carries it over to the main AFC.

As I mentioned, the machine became quite popular, since it both cut the coal, and loaded it onto the conveyor. However the small cross-conveyor needed to move the coal over to the main conveyor was relatively fragile, and frequently broke, dropping production. The scene was therefore ready for two more machines, one of which I will discuss today, and the other (when I talk about mining thinner seams of coal) in a later post.

The new machine was called a shearer. Developed by John Anderton, who worked for the British National Coal Board, the initial concept was brilliantly simple. Take the coal cutting machine that was common in many mines, turn it on its side so that the drive shaft was horizontal, and mount a cutting drum to the drive shaft that used to operate the cutter bar.



The picks on the drum were set on a spiral, so that as the drum turned it would feed to coal over to the conveyor, on which the machine was riding. The shape of the scroll, with and without picks, can be seen from the lower parts of the Anderton Shearer Memorial in St Helens. Lancashire.

(From Lowton Websites) The lower scroll shows how the shape would, as with a wood drill, feed the coal back to the conveyor as the drum rotated.

This proved to be a relatively simple machine, adaptable from existing machines in the mines and became the predominant mining machines for longwall faces. Over time the drum was mounted on a boom, so that it could range up and down to adapt to varying seam conditions, and a second drum, also ranging, was added to many machines, at the other end. In this way higher coal could be mined.


Modern shearer, showing the size, and how it would integrate with the AFC, on which it rides, ahead of the shield supports which protect the miners. (Note the coal face would be where the man is standing).

The machines need many less miners to operate that the fifteen men that would hand load out a face back in the early 1960’s, and now there are automated devices to detect the interface between the coal and the rock, and which can raise and lower the drums to adjust for these geological changes.

Looking down on a model of such a mining operation, with the front canopies of some of the shields removed to show how the conveyor “snakes” over. The operation of the face is as follows:

First the shearer mines off a web of coal that is perhaps 2-ft deep. This is loaded onto the AFC (green) and carried away. The hydraulic rams on the shields then push the conveyor over so that it is beside the face. Then, in turn, each shield lowers, and the ram is reversed, to pull it forward the same 2-ft so that it again covers the working area. It then raises, and resupports the roof, while the support next to it is advanced. In this way the machine continuously slices off the coal as it moves the face forward.

The technology allows high rates of underground production, for example, in May 2009 the Newlands Northern mine in Queensland mined 961,891 t from its longwall, 251,720 t of that in a single week. (And up to 46,000 tons in a day).

For those interested in the technical details:

The Newlands longwall is equipped with Bucyrus EL3000 shearers which have installed power of 1,590 kW and cutting power of 2 x 650 kW.

The shearer employs a jumbotrack 2000 haulage system with haulage power of 2 x 125 kW and is fully automated. The longwall is equipped with 147 two-leg roof supports with a yield load of 1,040 t and a working range of 3 - 5m. The face conveyer is a Bucyrus PF4, 1332mm wide with a 42mm twin inboard chain with 2 x 855 kW CST drives.
The longwall is controlled by Bucyrus PM 4 controllers, with the 400 kW PF4/1532 coal crusher and 400 kW SK11/18 beam stage loader also from Bucyrus, and motors manufactured at ATB Morley’s factory in Yorkshire.

Peak Oil, the DOE and interesting times ahead

There is a certain sector of public opinion, including the President, that apparently feels that for the sake of taking appropriate precautions, even if the current scientific thinking on climate change is wrong, we should act as though it is right. The problem that there is, however, in the way that the argument has been accepted, is that it has led to demands for dramatic change in the way that the Federal Government is looking at future energy supplies. I was talking with a colleague today who commented on how much the conventional research funding for fossil energy fuel production is being cut. And the problem with that is that you can’t have a baby in a month by making nine women pregnant.

What do I mean by that? Well the production of energy at the level of scale that is needed for the United States (let alone the world) is difficult for many people to grasp. And making a change that will have a significant impact on that supply, in a positive sense, requires an effort that is correspondingly large. Changes do not happen overnight. As the Hirsch Report noted, it will take up to 20 years to find and install a replacement for the falling world production of oil. Yet the technologies that were advocated in that document, written in 2005, were not that revolutionary.

Besides further oil exploration, there are commercial options for increasing world oil supply and for the production of substitute liquid fuels:
1) Improved Oil Recovery (IOR) can marginally increase production from existing reservoirs; one of the largest of the IOR opportunities is Enhanced Oil Recovery (EOR), which can help moderate oil production declines from reservoirs that are past their peak production:
2) Heavy oil / oil sands represents a large resource of lower grade oils, now primarily produced in Canada and Venezuela; those resources are capable of significant production increases;.
3) Coal liquefaction is a well established technique for producing clean substitute fuels from the world’s abundant coal reserves; and finally,
4) Clean substitute fuels can be produced from remotely located natural gas, but exploitation must compete with the world’s growing demand for liquefied natural gas.
However, world-scale contributions from these options will require 10-20 years of accelerated effort.

And they certainly aren’t being given a crash priority for funding from the Department of Energy. The Department, sadly, still seems to feel, complacently, that there is no critical need to be concerned about fossil fuel supplies, and that it is only the need for precautions to guard against producing too much greenhouse gas that drives the path forward with any urgency. There is nothing about taking enough precautions to protect against fuel shortages in the future.


Well, as I noted the other day, Asian and Third World use of coal is rising very rapidly, so that from that point of view I suspect that the Department is riding a crippled nag that is not going to help keep American industry competitive. Robert Rapier posted, the other week, on the costs of producing a million Btu from various sources. These were his numbers:

Powder River Basin Coal - $0.56
Northern Appalachia Coal - $2.08
Natural gas - $5.67
Ethanol subsidy - $5.92
Petroleum - $13.56
Propane - $13.92
#2 Heating Oil - $15.33
Jet fuel - $16.01
Diesel - $16.21
Gasoline - $18.16
Wood pellets - $18.57
Ethanol - $24.74
Electricity - $34.03

The electricity price is the EIA average retail price to customers. He provides both the sources for the quotes, and the energy conversion rates between fuels. (Powder River Coal from Wyoming runs at 8,800 Btu/lb or thinking of it another way a ton of coal produces 17.6 million Btu). You will note how cheap the coal is.

Is it any wonder that the Chinese are trying to negotiate a 20-year supply of coal from Australia to the tune of around $60 billion. The coal will come from the Galilee Basin in Queensland and will run at 30 million tonnes of coal a year for 20 years.

The China First project will be located in the Galilee Basin region near Alpha, west of the town of Emerald, and will include four underground mines, two surface mines, plus associated handling and processing facilities.

It will be linked to a coal terminal on the Queensland coast at Abbot Point by a new 490 kilometre railway line. The company says the project, which is awaiting final approval by the Queensland government, will create 6,000 jobs during construction and 1,500 when operational.

Some of the confusion in the current press is that while there is a letter of intent and a framework agreement, there is not yet a defined price for the coal.

Again, however, to put that in context, China uses coal both for industrial use (steel making) and for electricity generation with about half going to each at the moment. The EIA anticipates that in 2015 it will use 37 quads for electricity production, 30 quads for industry and 3 for other uses, for a grand total of 70 quads. A quad is a thousand trillion, or a million billion Btu’s. Dividing by the 17.6 million Btu’s per ton, means that by 2015 China will be using roughly 4 billion tons of coal a year. (The USA for reference produced 1.46 billion tons in 2008). So the Chinese are going to have a supply (though not that much of their needs) of relatively inexpensive coal. And there is a lot more coal in the Galilee Basin (more than 4.5 billion tons).

Here in the United States one of the current thoughts is to keep investing in ethanol production, which is impacting corn use. For example, of the 11.11 billion bushels total, 5.56 billion bushels go to food, seed and industrial use, 4.3 billion goes to Ethanol; 2 billion bushels to exports; and there are 1.7 billion in year-end stocks. (Note: this table as been corrected, and the source, following the comment below).

The numbers that are being used are measured (coal or corn) in billions. The top producer of corn in the United States last year produced 314 bushels of corn from an acre (the national average last year was 162 bushels/acre so to produce that much ethanol requires a lot of acres. And it has taken a significant amount of time to plan, fund and install the refineries – and in poor economic times some of those have gone bankrupt.

But we are not looking for innovative fossil fuel production, this complacency flies in the face of an increasing number of voices, Richard Branson being one of the latest, who have discovered that we don’t have 20-years. His figure for Peak Oil is five years. That may be optimistic, and may be within the continued term of an Obama Administration. So how are they preparing?

Realistically they aren’t. What they are funding cannot be brought to the level of production that can have any impact on supply within the five or ten year period. And when the crisis comes you can’t find the answer in the short term by just throwing money at it, and getting the fast result (the baby model).

As they say, life is going to get interesting. (Wait a minute, wasn’t that part of some curse or other?)

Burning coal in place, or Underground Coal Gasification

Last week I wrote about the SAGD process and how it is used to extract the heavy oil/bitumen from the oil sands up in Alberta. What I will write about this week is the more general topic of In Situ Combustion, and I’ll talk about coal this week, and perhaps THAI next week.

This is one in a series of weekly posts that deal with the technologies of conventional fossil fuel recovery. They are relatively short and so the descriptions are not provided in detail, rather they are meant so that you can understand some of the complexity of the process, and that it is not always easy.

The way that we use the majority of the coal, oil and natural gas that comes out of the earth is to burn it so that we can generate heat, which in turn is then used productively, either in the generation of electricity or more directly. But getting the fuel out of the ground can be quite expensive, either in direct cost or in the amount of energy expended. And so the question, why can’t we just burn it where it is to get the energy out more easily?

With most deposits the costs of recovery of the fuel conventionally are still low enough, and the energy recovery at the surface sufficiently high that this would be a losing proposition. But where coal seams are thin, or the oil is thick, using part of the fuel underground to recover a significant portion of what is left can be a winning proposition.


Of course burning coal underground is not always a deliberate act. Coal seams have caught fire for a number of reasons, and in parts of the country have burned for decades with significant environmental problems at the surface. Part of the reason for this is that if the coal seam is relatively close to the surface, then as the coal is burned away the overlying rock collapses all the way to the surface, opening cracks which allow air to get down to the burning zone, in this way providing oxygen that helps keep the fire burning. If the fire is burning uncontrollably then it becomes much more difficult to establish control since the cracks to the surface help keep the fire going and may not all be that large and easy to detect. (Though I have seen some big enough to hold a cow’s carcase).

My own first encounter with underground coal burning was when wandering into a mine that was something like a hundred years old, and being conscious of all the smells in the return air-way. I was told that an old part of the mine had spontaneously caught fire, could not be extinguished, but had been sealed off and left. The fire, in that case, was fed oxygen through the mined out passages around the place now on fire.

Which brings up the first point, which is that coal can, on its own, catch fire. The old pit heaps that dotted the landscape around mines were made up of old coal waste, including a fair amount of un-recovered coal. When they were later reclaimed it was often found that the tips had caught fire and burned the clay into a red-brick-like material. This self-ignition is known as spontaneous combustion and occurs because coal reacts with atmospheric oxygen even at ambient temperatures and this reaction is exothermic. If the heat liberated during the process is allowed to accumulate, the rate of the above reaction increases exponentially and there is a further rise in temperature. When this temperature reaches the ignition temperature of the coal, it starts to burn - hence the term "spontaneous" combustion.

The temperature at which the coal oxidation reaction becomes self sustaining and at which spontaneous combustion occurs varies generally depending on the type (nature and rank) of coal and surrounding conditions of heat dissipation. In poor quality coal and where the heat retention is high the coal and carbonacous material may start burning at temperatures as low as 30-40° C.

Coal oxidation can occur in coal storage – even on a battleship and, as I mentioned, underground

The fires are not always spontaneous, perhaps the most famous is the Centralia fire which Joan Quigley has written about in “The Day the Earth Caved in.” where the coal seam outcropped at the surface, and where it caught fire, and the fire then moved underground and beneath the town of Centralia, PA. Despite vast amounts of effort, money and time, the fires are still burning.

Which brings me to the second point. For a fire to continue to burn it has to have fuel (the coal) and air (oxygen). If the fire is totally cut-off all the air is consumed and the fire goes out. But if there are cracks through which air can reach the fire, then it will continue to burn. Thus, in Centralia, for example, as the coal burned in and under the town, it removed part of the rock holding the town where it was. The ground would then collapse into the burned out cavity, and a crack would run up to the surface along the edge of the opening, allowing air to flow back down to the fire and continue the progression.

Having been once involved in fighting such an event, it is very difficult to tell where the fire front is, and the coal does not burn in a vertical front, but in a very jagged pattern, depending on air flow and relative composition of the different layers of the coal. The air generally flows through the cleat pictured here.

But knowing that coal seams can burn in place, we still have to work out how to make that useful. Short of running water pipes down, and using the steam that comes out for power surely there has to be a better way of getting the energy, and there is.

Before the advent of North Sea gas British towns were dominated by the Gas Works, old gas-from-coal plants that produced town gas from coal. Simply put by heating the coal, and passing air and steam across it, one can generate "producer gas' and

"The final composition of producer gas is about 12% hydrogen, 25% carbon monoxide, 7% carbon dioxide, and 56% nitrogen; the nitrogen comes from the air used in the producer gas reaction." So that if we can get the water and air to the coal fire underground in the right quantities then we can generate a gas that we can extract and it can be used as an energy source.

Sounds easy, right? It turns out that it is not quite that simple. From the BERR report on the Chinese work written in 2004.

Underground coal gasification (UCG) experiments have been carried out in many coal mining countries and industrial scale production has been achieved in the former Soviet Union. More than 15Mt of coal has been gasified by UCG and in excess of 50 billion m3 of gas has been produced from UCG projects around the world. Despite research and many trials in different countries, no truly commercially viable UCG project has yet been demonstrated. However, various technologies are now available which could change this situation. A shallow seam, commercial power generation project is currently under development in Australia.

The first major plant was at the YEROSTIGAZ facility in Angren, in Uzbekhistan which started in 1961, works a brown coal deposit and is now run by Linc Energy. The plant produced 35 million cu ft of synthetic gas a day, which is fed into the local power plant.

Advantages of the process are seen to be:

* Capital investments in construction of underground coal gasification stations are less by 2.5 times as compared with those in construction of pits and quarries.

* The productivity of labour is the same as in open-cut mining and 4 times as high as in pits while the cost of final product being the same as in open-cut mining is 3 to 4 times as low as in extraction from pits.

* Hard and dangerous underground labour becomes unnecessary, working conditions are much better, and the extraction process can be completely mechanized and automatically controlled.

* Coal transportation, loading and unloading are excluded. No fuel is lost in transportation to the user and the atmosphere is not polluted with coal dust.

* There is no necessity for large areas for waste and ash dumps, and this allows conservation of fertile soil. The cost of land recultivation is five times as low as that with the conventional method of coal extraction. The mineless method of underground gasification allows exploitation of coal deposits with unfavourable mining conditions unsuitable for underground or open-cut mining. This allows more complete utilization of coal resources because non-conditioned and over-balance coal reserves can be used.

* Unlike coal combustion, the –underground gasification requires no fuel preparation, and consequently, no ash and slag disposal. No environmental pollution occurs because the gas combustion products are free of solid particles, carbon oxide, sulphur and nitrogen oxides.

The process is illustrated:

Angren UGC process

Linc has since opened the Chinchilla UCG operation with initial tests in August of 2008, running only air into the coal and recovering gas.

During its almost seven months of operation, the generator has operated very stably, producing gas of consistent quantity and quality. Gas has been produced with a typical composition (on a nitrogen-free basis) of H2 32%; CO 17%; and CH4 18%. The H2/CO ratio of 1.81 is ideal for Linc Energy's GTL process. Since commencing operation of the 3rd UCG generator, Linc Energy has gasified approximately 2000 tonnes of coal, producing over 5 million Nm3 of synthesis gas.

China began building an industrial scale pilot plant in Inner Mongolia in May 2007.

Seven ignition and production wells reached the coalbed 200 meters below ground by May 23 in the project's $112 million first phase. The project consists of underground drilling and ignition, aboveground coal-gasification power generation, and chemical production.

The plant is located at the Gonggou Coal Mine in Wulanchabu City and by 2010 will produce 1.5 million cu. m/d of syngas, 100,000 mty of methanol and methane and generate 32.4 million kwh/y of power. The city is developing a coal-chemical industry with its more than 15 billion tons in coal reserves. Methane isolated from the syngas will be used to produce town gas and generate electricity.

In Australia Carbon Energy having run a successful 100 day study has started to install a 5 megawatt generator at Bloodwood Creek.

Let me, briefly, concentrate on two problems.

In the initial concept, it was proposed that two wells could be drilled from the surface to the coal seam. In one early US test of this idea, in Hannah WY, the seam was relatively close to the surface, and for the first test the wells were set 75 ft apart. After reaching the seam, it was intended that the connecting passage between the injection well and the extraction well would be created by starting a small fire at the bottom of the seam, at the first producing well, and then by blowing air down the injection well have the fire work back to that well along the cleats through which the air was passing. By restricting the flow it was intended that the passage would be small, and run along the bottom of the seam. Then, once a passage existed, more air and steam could be fed into the injection well, increasing the size of the fire, and creating the producer gas that could be extracted from the production well.

Unfortunately the fire would not "behave" and over-burned the coal, rather than burning in the lower section, and did not otherwise go as planned. The conclusion was that this passage had to be artificially created first. The need for a long hole in the coal requires a directional drilling tool, and in the 1970's when the earlier trials were made, those were not available, particularly ones that could turn ninety degrees within the 140 ft from the surface to the seam. One had to be invented (and was). Thus in recent experiments the UK planners have looked at directional drilling from the surface to the coal, as a way of creating the initial passage, and providing paths for the air and steam to the fire and for the producer gas to come out.

Source UK Coal)

Two different approaches are being looked at in China, one of which works by creating panels in existing mines from adjacent cross-cuts, while the second uses a pair of directionally drilled holes with the fire to be initiated between them. Although as I mentioned from the work done in the US, getting that initial connection may be rather difficult and long-term control of fire location gets to be rather tricky.

Chinese method of UCG Derived from the BERR report.

The use of the two bounding holes confines (in thinner seams) the burn to the geometry desired and gives a method of control that is more difficult to achieve in larger seams, or without those bounds.

Richard Heinberg’s “Blackout - Coal, Climate and the Last Energy Crisis”

When this new book was about to be published the editors at The Oil Drum were offered a review copy, and I was offered the chance to provide that review. Yet in a way providing that review gives me a bit of a puzzle, because the underlying premise on which the book is based is that, as David Rutledge has propounded, the world will run out of realistic coal reserves much faster than most folk anticipate. It is a point of view that I don’t completely accept, and I have posted on my disagreements with Dr. Rutledge over some of his assumptions and conclusions in the past. So I could fill this review with another regurgitation of my points of disagreement, but were I to do so I don’t think it would be a fair review.

The book sets out to collect together in sequential order a compilation of those views that state that the world will run out of coal faster than expected (including one source that disagrees); then looks at the coal remaining in the major consumers the United States; China; Russia and India; and then looks at potential exporters Australia, South Africa, Europe, South America, Indonesia and Canada, as it rounds out the major global patterns of coal trade of the world. The interplay with coal and climate is then reviewed and three different paths forward are then offered, with some closing remarks. It thus provides a relatively concise, yet comprehensive review of the coal supply future from one perspective. That is a very useful thing to have, and (perhaps I shouldn’t admit this) had I not been given a copy for review I would have bought one. Would I have got my money’s worth? Well it depends on what you are looking for. And to explain that remark let me discuss, very briefly what is in the Chapters and what I would argue about.

The fundamental questions come down to the difference between reserves and resources, and the rate at which reserves are used up. However because use changes as production declines and product cost rises, there needs to be some model of declining production. The references that the book cites rely on Hubbert Linearization, and this forms the basis then for the estimates. The text explains how it works and notes that it has often, historically, been applied to estimating how long oilfields will last. This model is then used to predict how long the current reserves of the different countries will last, based on current reserves. The resulting numbers are quite dramatic. China is shown, for example, to see a peak in production around 2020. Given that China produces, and consumes, around 40% of world production – twice that of the United States – the impact on overall world use is likely to be significant. For while, for example, Russia is quoted as having the second largest reserves, the book estimates that “Russia could well cease being an exporter within only a few years.” (Part of the problem rises because some of the eastern resources have yet to be tapped, and even when they are the coal has to be moved to the west where the demand is. Russian transportation services are considered currently inadequate to the task.)

In looking at India the author did give me my one mention, when looking at the potential increases in production that might be achieved by Coal India. But he points out (as I have) that India has a serious current fuels crisis and that increasing coal use is one way to solve it, at least transiently. I did think it a little odd that Pakistan, which also has serious supply problems, and is right next door, only got the courtesy of a passing reference “While the situation in India is not yet as bad as that in neighboring Pakistan, . .” The situation in India is not getting better – as an aside - and remembering that Bangalore is where a lot of India’s IT is located:

The situation is going to be grim across rural Karnataka. People in the rural areas will get electricity just for 10 hours, of which the three phase supply will be available for only five hours. It will be 14 hours of darkness in rural parts over the next 12 months. That is only if the authorities do not take recourse to unscheduled load-shedding as they have often has done in the past.



Energy Minister K S Eshwarappa on Thursday announced that Bangalore would have to bear with two hours of regulated load-shedding –– an hour in the morning (anytime between 6 am and 10 am) and another hour in the evening (anytime between 6 and 10 pm).

The situation for both India and Pakistan is that they are therefore going to be increasingly reliant on coal, and as the author points out, India is not yet set up to produce enough for its own needs, which as the above quote from this week shows, are becoming more critical.

And so these nations must turn to imports, and thus Chapter 5 deals with those countries that are most likely to provide that coal (Australia, South Africa, Europe, South America, Indonesia and Canada). Sadly it is this chapter that is the most disappointing, since the question as to whether the world will continue to have enough coal, is going to depend on the ability of the global production units to supply it. The book only recognizes South Africa (the country) as being capable of coal production in Southern Africa (the region) and being the only country there with significant reserves. However when South Africa started defaulting on power to neighboring countries at the beginning of 2008 those countries had to look to what they can do with their own resources, and in Botswana, and Zimbabwe, among others, this will mean coal. Chinese engineers have already been engaged to increase production, and there is talk of the country matching or exceeding its diamond income with the income from coal, based on a 200 billion ton reserve. (In the book South Africa is quoted as having 48 billion tons of reserves. The Botswana reserve was only a resource until S. Africa cut off supplies). Admittedly there are currently some problems getting that program going, since initial plans for electricity production exceed local needs for power.

Europe gets similar short shrift, with UK reserves and production being written off in just less than a page. And so we come to the chapter on climate impacts, that begins

Recent reports on global coal reserves, surveyed in the previous chapter, generally point to the likelihood of supply limits appearing relatively soon – within the next two decades (a contrary view is represented solely by the BGR report). According to this near-consensus, coal output in China, the world’s foremost producer, could begin to decline within just a few years.”

I am tempted to quote the shortest sentence in the Bible. Of course, if you pick your sources, you can get a consensus on anything. For the record I objected to David Rutledge’s point of view, not only at ASPO, but later in The Oil Drum. (I wrote both about the National Academy report on coal, and the known coal reserves in the UK (determined by measurement and observation) not theoretically, and as defined in Trueman’s Coalfields of Great Britain. I listed the tonnages available from that text (though putting Scotland inexplicably in England for the table). That coal has not gone away, and some of it was being mined up to the time that North Sea Oil and Gas came ashore and turned it all (and this is key) temporarily from a reserve into only a resource.

This is not the place to get into more debate on the causes and status of climate change – or of the arguments that Richard Heinberg makes – if you believe they will reinforce that belief, if you don’t you can nit-pick over those he got wrong. But that isn’t the purpose of the chapter, rather it is to look at how the impact of an early peak in coal production will affect carbon dioxide levels. Recognizing that there is going to be a peak in the production (and use) of all three of the major fossil fuels (oil, natural gas and coal) that may be very imminent means, as the author points out, that most of the IPCC models overstate the levels of carbon dioxide that we face in the next century. And thus, initially, the news is good in that the limits of concern will not be reached.

However the author questions the consequences of further warming, being concerned over, for example, the thawing of the permafrost and the release of methane as an additional forcing to the climate, and foreseeing additional problems beyond those currently anticipated. Thus he concludes that the peaking of the fuels won’t solve the problem. On the other hand he notes that climate change concerns are reducing the number of coal-fired power plants being considered in Europe and the United States. Thus perhaps climate change will influence Peak Coal?

One way of solving both problems relies on the introduction of new technology. So in the penultimate chapter there are short reviews of IGCC; CTL; UCG; and CCS though without any projection of hope that they will do much good in resolving the problem of carbon dioxide emissions. And so, in the final chapter three scenarios for the future – one which sees no coordinated plan for the future sees the global economy in ruins by 2040; one that sees a massive investment in CCS and IGCC but yet again, despite that effort the world energy demands are not met and global ruin again arrives; and then there is a third scenario where, through strong central government action (and a declining world population) the world is saved. (I will let you buy the book to see how that happens).

Yes, I am going to keep the book around, not on my desk, but somewhere so that, in five years or so I can pull it back out and see how the world did move on. I have a number of books from the 70’s (including a couple by Daniel Yergin) that predicted the then future 20-years of growth, and how without following certain paths we would be doomed. They proved to be quite wrong, each in their own separate way, as this might prove to be. Natural gas, for example, at the moment may play a stronger role in the future than is currently projected.

But that is the fun of future projection – this book gives you some insight into the debate about the future of coal – I disagree with many of the assumptions and projections, but it does define the arguments of a given viewpoint that is receiving increasing levels of attention. So, yeah, I’m glad I read it.

P53. Pick Points

Half-a-dozen or so stories that might be of interest:

There does appear to be a little recognition out there now that oil prices have hit a floor, and may perhaps be bounding up a little. I suppose if I was that kind of blogger I would point to the post where I said so, but let’s be a little cautious a week or so longer. Ecuador thinks that the price should really be $80 (per barrel) but would be happy with $60. Although Shell admitting they weren’t replacing their withdrawals from reserves, might also have helped. With some of the excess oil that has been held in tankers now coming onto the market perhaps others are seeing the sort of signal that says we may now see a crawl back up in price. It was only a month ago that something like 80 million barrels was being held in these vessels, given that a VLCC (Very Large Crude Carrier) can hold up to 2 million barrels, and with 45 tankers having been used that way, there was a lot to ease back into the market. Shell sold their first two tanker loads (some 1.2 mb) back at the end of January and it seems that others are now also finding a sale.

The lower supply price for natural gas is now reaching the point (as winter demand dies) that supply companies are starting to pass on their savings to the customer. For example up in Canada, Enbridge Gas Distribution has just go permission to drop their price from 30.4 cents per cu.m to 23.5 cents. For a household using 3,000 cu m per year, this will save some $230. (That price converts to a drop from $8.60 to $6.65 per kcf). Similar things are happening in New Hampshire with the utility there, Unitil Corp, is getting a new rate of 69 cents per therm, (or $6.90 per kcf), which is down 26% on recent prices, and 56% from last summer’s peak ($15.50 per kcf). There are some out there, however, that have picked up the message I have mentioned here earlier, that as rigs drop off, so availability will again become tight, and thus prices could double again by next year. Next January’s futures are up 49% on April. However, while I was looking at a 20% shortfall some time into early next year, with the current fall in production, some are seeing 5% drops by the fourth Quarter. And looking back in history (which I favor)

The last time drillers stopped rigs at this pace was seven years ago, when futures advanced 86 percent. The world's biggest hedge funds have already started to close bets on a drop in prices, government data show. Natural gas tumbled 30 percent this year, the worst start since 2006, as sales weakened with the recession.

I usually only just look at the weekly EIA numbers for crude, gasoline and natural gas, (and those comments may be a few hours delayed since I am working in Sweden) but it is worth having a quick peak at the coal forecasts, which come out on Monday’s. For reference here are the current spot prices for coal:

Source EIA

In case you were wondering why most utilities are buying Powder River Coal from Wyoming. The amount of coal being produced and used is remaining fairly stable.

Source EIA

The blue line for last year shows record production levels, that are, at this time, not anticipated to occur this year because of the economy. However, when one looks at the international market, where last year saw record prices of up to $300 a tonne, (sometime I will start correcting for the difference between short tons (US) and metric tonnes (most others)), the market is currently looking at prices of around $115. Of course that view came from New Zealand, where a new coal offering was fully subscribed. Australia is hoping to settle, for the moment, at around $70. But those who think that the global slowdown will seriously reduce consumption, might want to consider that China’s imports were at the highest level in 22 months in February, at 4.88 mill tons, and with prices being bruited of $62.10 per ton in Newcastle, Australia, they may not be the only ones that come calling. (But part of the demand relates to internal Chinese politics over the price utilities will have to pay the mines for coal). It might also be worth noting that in order to sustain their economies both China and India are pouring money into infrastructure, and that means steel, and steel means iron, and iron means coal. India is going into elections this year, in case you had forgotten. However the number of ships lined up to take coal at Newcastle has dropped from 70, eighteen months ago, to 15.

Well having just skimmed around the big three tonight, I thought I’d leave room for a couple of pictures. Back when we went to Cork for the ASPO Conference , Colin Campbell laid on a piper to lead us in to dinner. Well I was led to where I was ended up deciding to eat tonight by pipers* in the Stockholm Gamla Stan.


Pipers in Stockholm

And then when I wandered back to the hotel, I found that the Royal Palace had been surrounded by a belt of snow about a street wide, and some 20 cm (8 inches or more) thick of artificial snow. Maybe they thought I missed it, or was expecting it (it was snowing when I arrived). Anyway, not a good picture in the light, but just to show, these are normally the steps up to the Royal Palace.

Snow covering the stairs into the Royal Palace

(it’s artificial, and 20 cm plus deep)
* I actually dined on moose, and cloudberries, just around the corner.

P47. Pick Points

Half-a-dozen or so stories of interest:

Up in Canada Suncor expects to produce around 300,000 bd of crude from its operations in Alberta. But all is not well in those operations. The rise and then fall in petroleum prices has had a significant impact on the oil sands industry.

Companies financing oil sands projects out of cash flow have been relatively unscathed, besides suffering substantially lower stock prices and having to delay projects due to lower revenue. Companies financing oil sands projects on credit are up for sale at bargain basement prices. The most likely buyers of those credit-short companies are supermajors and sovereign wealth funds.

The Canadian and Albertan governments have lost substantial tax revenue because of rapidly rising project costs eating into corporate profits. Relatively more upgrader projects being delayed or cancelled compared to mining and in-situ projects contributes to less value-added in Canada and a lower tax base for those governments.

The article goes on to discuss the significant costs of a cap and trade rule for the oil sands, and the potential serious consequences to the industry if it chooses to ignore that coming freight train. The report anticipates a cost of $80 a ton for carbon from operations on the scale of the oil sands.

In order to help the industry the Alberta Government is slashing royalty rates. The Alberta Government has also set aside $2 billion for work on carbon capture and storage for the oil sands and coal. There are however some doubts that the effort will result in any significant benefit. The current article in National Geographic has stimulated debate on the issue. But it has also brought a note that, if America does not want oil sand crude, (or makes it difficult to buy through CCS legislation) then China is ready to move in and take the oil instead. In Australia, meanwhile, a company has suspended its work on underground sequestration due to the plunging prices of permits (the problem that Europe also has).

While wandering around the various websites looking for comment on the demonstration at the Capitol Power Plant yesterday (which was a lot less dramatic that the organizers had intended I suspect, and a lot less well attended, I came on a couple of other folk that had been watching the video feed. One of them was OpenMarket who quoted a couple of interesting reports about some of the downside of moving from coal to other renewable fuels. The Reports were: M. Harvey Brenner, Ph.D., “Health Benefits of Low-Cost Energy: An Econometric Case Study,” AWMA Environmental Manager, November 2005, and Adam Z. Rose, Ph.D., and Dan Wei, “Economic Impacts of Coal Utilization and Displacement in the Continental U.S., 2015” (Penn State University, supported by a grant from CEED, July 2006). These looked at the conditions that would occur with different coal future production levels. The results were along the lines of

An econometric model was applied to a hypothetical regulatory case study, whereby U.S. coal was replaced by alternative higher-cost fuels such as natural gas for the purpose of electricity generation. The model was used to estimate the premature mortality associated with increased unemployment and reduced personal income. The adverse impacts on household income and unemployment due to the substitution of higher-cost energy sources were estimated to result in 195,000 additional premature deaths annually.

Somehow I doubt if we will hear much of those findings.

Pemex is sticking to its target of 756,000 bd from Cantarell this year, even though apparently their own figures are showing production is dropping at 7% pa. They are having some success with the Tsimin-1 exploratory well that came in with 4,400 bd of oil, while the Cali-1 well in the Burgos project is producing at 9 mcf/d.

Russia is signing energy deals with Spain that include renewable energy collaboration. This might bring the Spanish oil company Repsol into working on the Yamal fields. Given that investors have been lukewarm to the latest news of Gazprom profits this agreement, and the promise of some Shtokman gas for Spain supplied as LNG starting in 2014, may be helpful, since it may bring in Spanish investors.

And a quick note on the coal situation in Bangladesh. Apparently the Chinese company that has been working on the Barapukuria coal mine has told the authorities that if the mine does not start this week, they would pull out. The operation is tied up in compensation claims.

More stories can be found at The Energy Bulletin and Drumbeat at The Oil Drum.