Waterjetting 21d - confined coal transport

Collecting the material that a high-pressure waterjet has dislodged from a surface can be carried out in a number of ways, depending on the scale and volumes of material that have to be removed. One of the initial problems that arise depends on the energy of the jets that are striking the target, and the part of that energy that remains in the water and dislodged particles after the jet impact.

If a surface is relatively smooth (think for example of a ship hull, or the deck or sides of a bridge) then when a jet has hit the surface and removed the small amount of material (such as rust or paint) it will likely continue in a relatively straight line forward, since the surface roughness of the target, while disrupting and flattening the jet, has not sufficient angle to radically change much of the flow of the jet.

Which might make it time for a little recap. One of the experiments that I would run with an introductory undergraduate class was to give each student a high-pressure lance, and then have them hold the nozzle just above a target surface. The pressure of the water being fed to the gun was then slowly raised, and as this occurred the jet went from striking the surface and then just flowing along it, when there was no penetration or surface material removal, to being reflected back at the lance holder.

The reason for this is that, as soon as the jet started penetrating into the material (usually a rock for the purpose of the demonstration) then the water is entering a hole where the only exit is back the way that it came in. It is a salutary lesson for the lance holder since all of a sudden the jet is coming straight back (which is why all the personal protective equipment is an important part of the lesson).

This only holds true where the jet is hitting a relatively flat surface in an approximately normal or perpendicular axis of attack. In the more general case the cut along the surface will cause the water and debris to scatter in a more general spread, and it becomes a more difficult job to collect both back together in a way that allows both to be contained and removed from the site (an increasingly important part of the environmental parts of the process).

There are places, such as steeply dipping coal seams, where the geometry of the excavation itself helps to confine this ejecta and direct it, under gravity, to fall into a narrow space where the water and coal particles are brought together so that the coal is suspended in enough water that it can then be carried away from the work zone.

Perhaps the best example of this was the Sparwood mine in British Columbia in Canada, where the mine was extracting coal from a seam that was roughly 40 ft thick, and which dipped at around a forty degree angle.

Figure 1. Section showing the Sparwood mining plan

Drifts were first run at a slight angle (this started at six degrees, but after lining the flume with Teflon plates the mine was able to reduce this to just over four degrees) to the strike of the seam. This was a sufficient angle that, when all the coal was caught in the flume it would be carried down without settling by the spent water from the mining process, which was also trapped in the underlying drift, and held by a barrier across that drift. The shallower the angle then the more coal could be recovered above the main haulage ways at the back of the working area.

The mining tunnels (drifts) were first driven to the back of the section, using a small road heading machine to extract the coal, while installing a flume along the side of the drift so that the coal could be immediately transported away as it was mined. Full support to the tunnel was also installed using arch girders, with bracing wooden slats between the girders. Once the drift had reached the end of the seam, then a hydraulic monitor was placed in the uppermost drift, and the arch girders and wooden planks removed from the final fifty feet of the tunnel, with the monitor placed under the last few tunnel supports of the remaining tunnel section.

Figure 2. Layour of the monitor within the access drift.

By using a jet of just over an inch in diameter. the jet was able to reach the back of the section of coal that had been exposed when the supports were removed (zone 5 in figure 2) a distance of over 120 ft. the monitor was moved by two sets of hydraulic rams, but if you note where the operator is standing at the back of the machine, this is some 40-ft from the opening and the mining operation itself is not visible.

Figure 3. A monitor in operation at Sparwood. Note the short length of the barrel, which would still produce a high-quality jet, since flow straighteners were used in the barrel, placed directly behind the nozzle.

The operator uses the rams to move the nozzle in an oscillatory path, and listens to the sounds of the jet as it strikes the coal. The sound is quite distinctly different when the jet is hitting coal, as opposed to striking roof rock or shooting into the open space of the drift updip. (I was told this, not having that experience, though I have found similar changes in sound useful in other applications that I will discuss from time to time). It takes, apparently, a couple of days for an operator to be able to consistently detect and use the sound differences to be able to effectively mine with the monitor.

Figure 4. Operator at the Sparwood mine, standing at the back of the machine, and beside the flume.

The way in which the coal broke under the jet attack was only controlled by the operator to a limited extent, so that there can be a significant volume of large coal surviving into the lower entry for collection, and flume transport needed a smaller size distribution. For this reason the coal company installed a coal breaker at the entry to the flume so that the water carried the coal lumps through the breaker, and only then did they enter the flume (Figure 4).

At the time that I visited the site the slurry was higher than shown in the above figure, with coal overlying parts of the back of the breaker. To make it easier to operate the breaker, while keeping the operator safe behind the roof supports, a second small monitor was set by the operator which could be used to clear off the machine from time to time.

The machine was operated by two individuals and over the course of ten years averaged a production of over 3,000 tons a shift. It was also for many years, the safest mine in Canada. To put that production in perspective, in those years an average section in the underground mines in Illinois, running a continuous mining machine, might average about 700 tons a shift, and would need about 14 men to achieve that target. (Production rates have since risen considerably as automation and remote control have reduced the number of folk needed, while higher-powered machines now produce greater coal volumes faster.)

Yet the range of seams where this type of mining can succeed is limited, particularly in the United States, and in coal seams that do not dip as steeply it becomes more difficult to control the particle and water spread as it leaves the impact region.

I’ll talk about a specific way that one can, on occasion, change that, in the next post.

Tech Talk - Of production stability, peaks and the future

Jeffrey Brown (Westexas from TOD) is quoted extensively in Kurt Cobb’s recent piece that points out that global crude production has pretty reasonably stayed constant at between 64 and 67 mbd since 2005. (H/t Nate Hagens). While there has been a total increase in the total refined products side of the house (with the total number floating around 90 mbd) this includes a number of different sources that, within generally defined standards, are not considered crude. The four main culprits that he lists are biofuels, natural gas plant liquids (NGLs), lease condensate and refinery gains. He makes a good point.

Figure 1. Crude oil production alone over the past decade (Kurt Cobb)

I can remember that it was some years ago, when looking at the OPEC reports on production, that I suddenly realized that the projected increases in NGL production made a significant difference in the overall volumes that they were producing. (It is anticipated to average 5.95 mbd in 2014). Back in 2001 OPEC just defined the fluid as natural gas liquids, but went through significant revisions of numbers in 2002 and in March 2004 redefined the volume counted as “OPEC natural gas liquids and non-conventional oils”.

Figure 2. NGL and unconventional oil production by OPEC (OPEC MOMR )

Over the past decade volumes have almost doubled. In the United States, with the increased development of the shale gases, production has also increased.

Figure 3. Increase in production of NGL in the United States (EIA )

The price obtained for these fluids, however, falls below that of conventional gasoline. For example:

Figure 4. Relative prices of NGL fuels relative to crude and gasoline. (EIA)

The EIA is reporting a continued growth in US production:

Altogether, in the Bakken, Niobrara, Permian, and Eagle Ford, oil production is expected to increase by 70,000 bbl/d in May 2014. The monthly growth rate is 3,000 bbl/d more than in April 2014 due to solid gains in Permian rig count and continuous rig productivity gains across the regions. While the DPR does not forecast weather impact, the spring thaw season has officially started in the Bakken region and may disrupt some drilling activity between now and June.

These additional resources take on an increasing importance as world demand is anticipated to increase another 1.14 mbd this year, slightly up on this year’s figure. This gain in demand was largely offset by increased production from the Americas, though OPEC note that overall global suppliy decreased last month to average 90.63 mbd but is expected to reach peak demand in the fall, at 92.24 mbd.

Looking at the supply side for this year, and bearing in mind that gains must more than offset lost production if the total increase in supply OPEC are projecting an overall gain in supply of 1.34 mbd, largely to come from outside of OPEC. This is expected to come from the OECD Americas (the USA, Canada and Mexico) group, while the increased production from countries such as those of the Former Soviet Union is expected, to rise by 150 kbd or less.

There has been relatively little change in the estimates of where the increases in North American production are anticipated to come. By the end of the year US production is expected to reach 12.45 mbd by the last quarter of the year. As OPEC noted:

Based on the US Energy Information Administration (EIA)’s monthly oil production report for January, regular crude oil output registered at 4.93 mb/d, tight oil production increased to 3 mb/d, NGLs output reached 2.64 mb/d and biofuels and other non- conventional oils recorded the highest output at 1.22 mb/d. The use of energy from biomass resources in the United States grew by more than 60% over the decade between 2002 and 2013 — primarily through increased use of biofuels like ethanol and biodiesel which are produced from biomass. According to the EIA, biomass accounted for about half of all renewable energy consumed in 2013 and 5% of total US energy consumed.

This month the OPEC MOMR focused on increased production from the Gulf of Mexico, with anticipated gains from the Olympus project at Mars B.

The total gain in production from the Gulf is currently anticipated to increase, this year alone, to perhaps 1.55 mbd, and to pass the previous record Gulf production of 1.8 mbd by 2016. In addition the Cardamom project is expected to add 50 kbd to the Olympus figure, and the start of oil production from Phase 3 of the Na Kika field is expected to add an additional 40 kbd to the 130 kbd which Na Kika is currently producing. However Gulf wells have a habit of going south a little earlier than predicted and I have borrowed the following graph from Ron Patterson which illustrates the cumulative fate of the combined Atlantis, Thunder Horse, Tahiti and Blind Faith fields.

Figure 5. Changes in production from major Gulf of Mexico fields over time (Ron Patterson )

When this is combined with Dennis Coyle’s prediction that the Eagle Ford field will peak in 2015, at 1.4 mbd, with a declining rate of production increase as one reaches that peak. Similarly the number of wells that can continue to be drilled in North Dakota in the sweeter counties of the state are limited, and beyond that there is a concern (which I have expressed before, and which others have explained much better than I) that as the estimates of production fall in the less successful regions of the state that it will become harder to raise the capital for the new wells needed to sustain and increase production.

That being said, I am beginning to suspect that this may be the year that the OPEC estimates for US production may get a bit ahead of what actually is produced. And if that is the case, then that means that the following two years will become even more interesting as the nations of the world start to realize that yes, there is a peak. Which might mean that the coal resurrection might be greater than I currently anticipate, but perhaps I will have more on that next time.

Tech Talk - Coal prospects

Last week was the annual Society of Mining Engineers annual meeting, this year in Salt Lake City, with the title “Leadership in Uncertain Times.” To illustrate the point it had some 6,000 members or more in attendance, as I hear and was quite successful from that point of view. However, through the grapevine I also heard that some of the mining companies are less optimistic of the future, with job offers made for this summer being withdrawn in several cases.

There is a considerable question as to the future of coal, as the title reflects, and this has as much to do with concerns over the construction or not of additional coal-fired powered stations around the world and the changing market as older plants are withdrawn from service. Some of the reason for uncertainty can be seen in the predictions from the EIA for the domestic coal market over the next year or two.

Figure 1. The decline in coal production in the United States over the past two years. (EIA)

The EIA note that last year was the first that production had fallen below 1 billion tons in the past 20 years. It does however forecast that production will increase this year by 3.9% before falling 1.5% in 2015. In both years however it will remain above that billion ton mark. I have written recently about the recent report “Warning Faulty Reporting of US Coal Reserves,” (in which the conclusion is drawn: “Rather than having a “200 year” supply of coal, there is now abundant evidence that the US is rapidly approaching the end of economically recoverable coal.“)

The two stories are, to a significant degree, discussing different topics, although the beginning of the Clean Energy report also discusses the rising price of domestic coal, and why – as it rises – so the switch to other fuels can be anticipated to continue. However, in that regard it is worth noting this other graph from the EIA.

Figure 2. Spot price of coal by basin over the past three years (EIA )

For those who forget 1 MMBtu (million Btu) is roughly equivalent to 1,000 cu ft of natural gas. The EIA also record natural gas prices and, in comparison to the coal price, that of natural gas – for equivalent energy – is considerably higher.

Figure 3. Natural gas prices (Henry Hub) (EIA )

Why then does the Clean Energy Report suggest that coal costs are going up, when as the plot above shows the spot price has been remarkably stable?

Figure 4. Cost of delivered coal in the US from 2004 – 2012. (Clean Energy)

Notice however, in this case, that the cost is for delivered coal, and the cost of that delivery is what has been going up over the past few years. (And you wonder why Warren Buffet invested in railways?

Figure 5. Changes in Railroad freight costs since 1981. (Association of American Railroads)

If you look at the plot you will see that the cost per ton-mile has increased fairly steadily over the past four years from just above 3 cents to 4 cents a ton-mile, which explains a significant part of the increased fuel costs. Railroad income has risen, since 1981, from just under $3 billion to $12 billion.

So what is the future likely to be? Well there is an additional source of income to the industry, outside of the US power plants, and that is through exports. Yet here the story is not really that different. Since 2005 the value of coal exports from the United States have tripled. This is not just a volumetric increase (which has happened with steam coal) but includes an increase from higher prices for metallurgical coal. (Powder River steam coal at 8,800 Btu sells for around $12.35, while the 13,000 Btu Northern Appalachian coal goes for $68.65 a ton. (This is one of the discriminating factors within the coal market that the Clean Energy Report fails to fully discern). Exported coal saw a steadily rising price from 2007, when it averaged $70 a ton through 2011, when it was priced at $148 a ton before falling to $118 in 2012 and to $96 in 2013. Roughly 46 million tons went to Europe in 2013, down from 51 million tons in 2012, while roughly 22 million tons went to Asia (down from almost 26 million tons). Of this about half the European and a third of the Asian coal was steam coal needed to feed coal-fired power plants.

The problem that the industry faces is that this downturn in both domestic and export demand that became evident last year is likely to continue into the next few years. In the case of Europe pressure to close coal-fired power plants continues, despite increasing concerns that the existing base is approaching a point where supply will no longer be able to meet demand. The Sunday Times carried a story this Sunday about Npower and their owner RWE, which produces 10% of the electricity in the UK, but which is writing off hundreds of millions of dollars as it devalues its current power stations, which are being closed by regulation, even as it fails to build replacements, which it is reported to find unattractive in the current political climate. Last December the NPower CEO noted that over the past year the spare capacity in the UK had fallen from 15% to 5% and if that continued this year (and there are more scheduled closures) then by next winter the reserve may be gone and the country may see the start of blackouts that will continue for some years.

In the same vein the United States is also cutting coal-fired production. An article in Motley Fool points to the trend over the next few years.

Figure 6. Projected coal fired power plant closure effects (EIA via The Motley Fool)

However this projection is possibly a little disceptive, since it does not foretell what might happen if “clean coal” can get a grip on the industry. As TMF points out:

But EIA's retirement projections may be too high. While air emissions standards will result in heavy fines, utilities may still foot the bill because of coal's relatively cheap production costs.

With natural gas prices up 50% this year to a four-year high, energy companies are scrambling to find cheaper energy. According to data compiled by Bloomber, an average natural gas plant makes $3.04 a megawatt-hour off its fuel, compared to a whopping $31.58 for coal-fired plants.

While coal might seem like a no-brainer bet, "clean coal" is far from a sure thing. Southern Company has been working hard to bring its 582 MW Kemper County, Miss., clean-coal plant online, but the $5 billion project is currently 65% over budget.

A Department of Energy report estimates that clean coal costs are roughly double that of coal, but companies like Southern Company are hoping to reinvent coal's future.

Unfortunately building new coal demand, when set against the destruction of current plant in both the US and Europe, will take some years and thus, while the future for coal might, in the long term be strong, in the shorter term one can understand why coal companies might be hesitant to hire new engineers. The reduced demand will, inter alia, lengthen to time that current supplies last, though I perhaps need to address that issue in a subsequent post.

OGPSS - The BP look into the future

So I suspect I should apologize. Here I am talking about the future projections for energy production that have been made by companies such as ExxonMobil and Shell, as though they were still the key and only players in the world. Yet, in reality, Saudi Aramco (12.5 mbdoe); Gazprom (9.7 mbdoe) and National Iranian Oil (6.4 mbdoe); appear in the list before ExxonMobil arrives (at 5.3 mbdoe), and then there is PetroChina (at 4.4 mbdoe) before BP arrives (at 4.1 mbdoe) and it is only then that we find Shell, which lies 7th at 3.9 mbdoe.

So the projections of the ExxonMobil’s of the world are of somewhat lesser value than they might, at one time, have been. (For those curious the list continues with Pemex (at 3.6 mbdoe); Chevron (at 3.5 mbdoe) and Kuwait Petroleum Co (3.2 mbdoe). This not only rounds out the top ten, it also closes out the list of those producing more than 3 mbdoe. (Abu Dhabi comes next at 2.9 mbdoe).

Yet, with those caveats, and recognizing that Saudi Arabia now produces only slightly less than ExxonMobil, Shell and BP combined, let me review the BP forecast, having already completed that for ExxonMobil and Shell. And while the latter two looked sufficiently far into the future as to obfuscate a little their shorter-term projections, BP is still focusing on the relatively short-term that runs to 2030.

Within that time frame BP expects overall energy demand to grow by 36%, though, as with the ExxonMobil projection, BP expects that a “tremendous increase” in energy efficiency will continue to develop, thereby slowing the need for future resources. They point out that, without this improvement in efficiency, global energy supply will need to double by 2030 in order to sustain economic growth.

This is particularly true for the United States, which BP sees approaching self-sufficiency in Energy, while it is the continued growth in demand from countries such as China and India and the Asian Pacific countries that provide most of additional need. Comparing their view from 2 years ago with the present there does not appear to be much change in the overall forecast. (Note that after the first two figures all the remainder come from the 2030 BP Energy Outlook).


Figure 1. Comparison of BP data and projections for population growth between their 2011 report (left) and that for 2013 (right)


Figure 2. Comparison of current and anticipated energy demand through 2030, from 2011 (left) and 2013 (right) BP reports.

There is a small increase in the overall demand from non-OECD countries in the more recent projection, but not a great difference. But this increase in demand reduces from a growth averaging 2.1% in the 2010-2020 time frame, to a growth of 1.3% in the following decade.

Within the period to 2030 BP anticipates that all major energy sources will continue to see an increase in overall energy production.

The fastest growing fuels are renewables (including biofuels) with growth averaging 7.6% p.a. 2011-30. Nuclear (2.6% p.a.) and hydro (2.0% p.a.) both grow faster than total energy. Among fossil fuels, gas grows the fastest (2.0% p.a.), followed by coal (1.2% p.a.), and oil (0.8% p.a.).

Figure 3. Growth in different energy sources through 2030

However, there is a change in the ranking of the different fossil fuels from the earlier projection. For while, two years ago, BP were projecting that coal, oil and natural gas would virtually tie in terms of market share by 2030, coal is now given a more dominant role, with natural gas falling below oil.


Figure 4. Change in market share for the different energy sources.

Coal is, within this time frame, not really bounded by available supply, though BP anticipate that more will be produced indigenously in the Asian Pacific than at present. Partly one assumes that this is necessary for financial reasons, although it will also be a need-based growth as the countries increasingly need electric power.

In terms of natural gas and oil supply questions are more urgent, and BP provide the following answer.


Figure 5. BP anticipated sources for the anticipated growth in demand for energy.

By far the largest production from the tight oil and gas shales will come from North America, where the current growth in production is anticipated to continue.


Figure 6. Anticipated production of tight oil and shale gas by region in 2030

One of the drivers that BP see, in the fall in oil demand, comes from its continued high price. This has already significantly lowered the use of oil as a power generating fuel, and the continued high price will drive the move to vehicles of increasingly greater efficiency. Thus, although global liquid fuel demand will continue to grow, it will only be at the rate of 0.8% pa, reaching 104 mbd by 2030. The sources to meet this are various:


Figure 7. Liquid fuel supplies through 2030

With the conventional supply of crude from non-OPEC countries diminishing, OPEC crude levels can be seen to increase over the next seventeen years, while the major increase in production from tight oils is anticipated to come from North America. In 2030 it will provide 9% of overall demand, providing almost half of the 16.1 mbd of overall increase in production. The increase will, however, slow post 2020, as the costs of production and the limits of the resource base. BP make the following prediction:

The US will likely surpass Russia and Saudi Arabia in 2013 as the largest liquids producer in the world (crude and biofuels) due to tight oil and biofuels growth, but also due to expected OPEC production cuts. Russia will likely pass Saudi Arabia for the second slot in 2013 and hold that until 2023. Saudi Arabia regains the top oil producer slot by 2027.

Other than tight oil, BP anticipates some increase in biofuel production, and from the oil sands, with significant increase in Iraqi production, and some gain from the remaining OPEC countries (one suspects Venezuela is included here) and from NGL production.

The largest increments of non-OPEC supply will come from the US (4.5 Mb/d), Canada (2.9 Mb/d), and Brazil (2.7 Mb/d), which offset declines in mature provinces such as Mexico and the North Sea. The largest increments of new OPEC supply will come from NGLs (2.5 Mb/d) and crude oil in Iraq (2.8 Mb/d).

In this regard BP believes that currently OPEC has a spare capacity of around 6 mbd, but will continue to cut production to sustain prices over the decade.

BP see roughly a 7% p.a. increase in shale gas production with most coming from the United States, Mexico and Canada. This will bring total natural gas production to 459 bcf/day by 2030. Of this North America will see a growth in production of 5.3% pa and by 2030 will be exporting roughly 8 bcf/d. In other countries the biggest growth will be in more conventional natural gas production, coming from the Middle East (31 bcf/d), Africa (15 bcf/d) and Russia (11 bcf/d).

This increase in supply, and the greater use of LNG tankers is likely to keep natural gas prices relatively stable.

OGPSS - China's coal industry

In this run-up to the election, the American Energy future seems to have faded into the quiet background. Gone are the concerns of past years, as both parties seem to have bought into the idea that the nation is well on track toward a much reduced need to import oil. Wood Mackenzie are forecasting that tight oil production will rise from 1.5 mbd this year to 4.1 mbd in 2020, with the Bakken producing 1.3 mbd, the Eagle Ford 1.3 mbd, the Permian plays (Bone Spring, Avalon, Wolfcamp and Cline) will produce 440 kbd, and the Niobrara should be good for 90 kbd. With the decline in production from the impact of Isaac in the Gulf not yet over, it is not yet clear whether the plateau in US production that was starting to form will continue, or whether the gains in production that these projections require will continue. But there are some signs that these projections are, shall we say, a little ambitious. Well costs are now running in the $9 - $11.2 million range and, to sustain production, in these formations where wells have a high annual decline rate, increasing numbers must be drilled each year to offset that decline, and the poorer quality of newer wells. But declining rig counts and other concerns are for the future, and if no one coughs too loudly we can pretend that everything remains fine until we get past November.

China does not have that luxury, since the country, having set its people on an upwardly mobile quality of life path, must continue to provide the power that such a ladder requires. As I noted last time, the potential gains from the increased use of natural gas have been noted. Actions have already been taken to make sure that future supplies will meet anticipated needs and work has begun to tap the gas shales of the country.

But despite those efforts the underlying strength of the Chinese power industry comes from coal.

In 2007 Chinese coal production contained more energy than total Middle Eastern oil production. The rapid growth of coal demand after 2001 created supply strains and bottlenecks that raise questions about sustainability.

In 2010 China produced almost half of the world’s coal tonnage.

Figure 1. A decade of coal production growth (EIA )

China produced some 4.52 billion tonnes in 2011 and some 45% of that was shipped from the mine to the customer by rail. As demand continues to grow those volumes will also increase.

Figure 2. The changing picture of Chinese coal demand and production. (Energy Export Databrowser)

Rail takes a much longer time to install than does a pipeline, and thus Chinese recognition of this need is timely. Between now and 2015 Government plans call for an increase in transportation capacity to 3 billion tons/year almost doubling current capacity, as production of coal is anticipated to decline slightly to around 4 billion tonnes domestically, which may only exist as a target value. Nevertheless to move the coal to the power stations where it is needed, not only trunk lines, but also a large number of shorter branches will have to be created. This will be particularly true if the market shakes out and many of the smaller companies, which are apparently currently seeing some cash flow problems may fade out of business.

Figure 3. Planned expansion of the Chinese Rail network (China Coal Resource )

The Chinese have always been willing to find creative ways of improving their mining technology. I remember back some 45-years ago, when the European coal industry was still strong though waning, and the Chinese arrived seeking to purchase up-to-date mining equipment. Given that coal demand and thus equipment demand was in decline, manufacturers were willing to meet the conditions of the sale. These included that engineers and technicians be at the manufacturing plant during the entire time that the equipment was being built, and that they fully how understand the process. (The argument was so that they would be able to maintain it, after arrival). Well needless to say after those initial deliveries, further orders were rare, and Chinese versions of the equipment appeared, and many of those European manufacturers are no longer around.

New developments of technology in the West are much harder to come by these days. Research and innovation in coal mining in particular has fallen on hard times in both Europe and the United States (to the point of almost disappearance) and thus as China moves toward automation of its mining, particularly in thin seam conditions they are less able to draw on external sources, and must develop more of their own.

Life is a little different in other ways also, and Western companies can now get into the country and collaborate on development. Peabody, for example, is now developing coal mines in China. It has also been working with the government of Mongolia and will help develop mines in the Tavan Tolgoi region. This may be the only growth region for the company at a time when the current Administration in the United States, not to mention those in Europe, seem bent on closing the industry down as fast as they practically can. Given the amount of power that will be required to sustain current qualities of life, and the disappointing, and expensive costs of recent alternatives, the question as to how long this long-term unrealistic view will prevail is a matter of conjecture. China seems to retain a more realistic view of what is going to be needed, and planning accordingly.

There have been some thoughts given to the possibility of sequestration of all the carbon dioxide that will be generated from the various power plants that use this coal. However the power plants are not necessarily close to places where it might be easy to sequester the gas.

Figure 5. Location of the major Chinese coal-fired power plants (The American)

Figure 6. An integrated map showing the power plants (CO2 sources) and the fuel regions together with the location of deep saline formations into which CO2 could be injected (NYT )

The Oil Drum has been fortunate over the years to have had a number of high quality posts on the development of the coal industry in China. These include a review by Dr. Minqi Li, hosted by JoulesBurn. In this review of Peak Coal and China, Dr Li noted that Chinese coal production is projected to peak in 2027, at a level of 5.1 billion tonnes. He estimates a total ultimate recovery of around 257 billion tons. Euan Mearns wrote about Chinese Coal when their consumption first approached 50% of global demand, and followed that with a second piece on the role of imports.

In addition Rembrandt has recently taken note of the developing Chinese coal to chemicals industry. As conventional oil becomes less available as a feed stock, so the growth of this effort will likely justify the development.

Although China has, in the short term (perhaps the next ten to fifteen years) enough coal to sustain internal growth in demand, it is nevertheless also moving pro-actively to ensure that it will have adequate supplies in the out years. Much has been made in the past of their activities in Australia, but, as I have noted, several times in the past the Chinese are becoming well established in Botswana, inter alia, in a country with almost no coal industry yet, but up to 200 billion tons of what are not even counted as reserves yet, because of lack of demand. This may be a lesson for the rest of us.

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.