Thursday, March 27, 2014

Waterjetting 19c - Of soil removal by water

The tragedy in Washington state, where a hillside slid down, across a river and destroyed and covered the small community of Oso on the other side is a reminder of the ways in which natural ground saturation can help dislodge large volumes of material. While it is unlikely that the exact trigger for the slide will be identified the underlying cause is well known. As water from the heavy persistent rains permeated down through the hillside it penetrated deeply into the sand, silt and clays that made up the cliff, filling the voids in the material and reducing the friction that held the slope together.

Once the water is between the grains there is a second stage, where the overlying water adds hydrostatic pressure to the water below it. This pressure starts to push the grains apart, further reducing the friction holding the grains together and, since water has no shear resistance, lowering the overall resistance to the gravity that is pulling the overlying material down a potential failure plane. Once the resistance falls below that pull the slope starts to fail. It happens very quickly and large volumes can move almost as fast as though it were just water. In this case the water moved roughly 15 million cubic yards of material off the mountain. and across the valley.

The power of water to move material once dislodged was an early part of the mining process, and an earlier post referred to “hushing” where water was first trapped, and then released to erode away overlying soil, and then ore, before carrying it down to a flume where the valuable mineral could be trapped and recovered. But it does not take much pressure to dislodge weak material. Russian studies* have shown that light soil can be moved with a pressure of only about 10 psi (which would be generated in the water at the bottom of a slope only 20-ft high), while medium soil would require perhaps 30 psi, and firm clay would need a pressure of about 100 psi before the jet would mine and erode it.

That ability to move soil using a monitor was further developed in Russia, where tests showed that it would take water flows of between 3 and 10 times the amount of soil being removed depending on the strength of the material. In the gold mining regions around Lake Bykal it lowered mining costs to 40% of that for conventional mining, and gradually the tool found wider application in general soil removal, being used in the construction of several dams, and also for soil removal during construction of the Moscow Canal.

An interesting example of the speed and effectiveness with which waterjets can remove relatively soft soil formations arose during the Yom Kippur War (10th of Ramadan War, October 1973) between Egypt and Israel. The Israeli Army had built defensive positions along the edge of the Suez Canal and these were mounted behind an earthen and sand barrier known as the Bar-Lev line.

Egyptian intelligence had determined** that the Israeli Army had assumed it would take 24 hours for this barrier to be breached, and a total of 48 hours for the Egyptian tank forces to successfully penetrate the line. The response time of the military units was planned accordingly. This time estimate was based upon the time that it was expected to take to make a hole 22-ft wide through the barrier, since this had, for each breech, to move 60 cu yards of material, and a total of 60 such holes were needed to get enough troops through to be effective. Conventional methods involving explosives, artillery, and bulldozers would taken over ten to twelve hours, and required nearly ideal working conditions. For example, sixty men, 600 pounds of explosives, and one bulldozer would have needed five to six hours, uninterrupted by Israeli fire, to clear 2,000 cubic yards of largely sand from the wall. Employing a bulldozer on the east bank while protecting the congested landing site from Israeli artillery would be nearly impossible during the initial hours of the assault phase. Construction of much-needed bridges for the main army would consequently begin much too late.

Figure 1. Using waterjets to breech the Bar-Lev line during the 1973 war (Mashpedia)

To deal with these 70-ft high sand and earth barriers, the Egyptians instead used water cannons fashioned from hoses attached to dredging pumps that were floated on platforms in the canal. A study was made of the speed with which different pumps could move the sand:soil mix and the initial tests with British pumps showed that it would take around 3 hours. But by combining them with larger German pumps into six pumps per breech the army was able to get the time down to about two hours, although it took a little time after that to deal with the residual mud on the floor of the breech and give an adequate road for the tanks and other vehicles. A total of 81 holes were made, moving over 3 million cubic yards of material.

Figure 2. Egyptian forces crossing the Suez Canal, showing the size of the breech created (Wikipedia)

The bridges were then put in place, and the Egyptian Army moved on into the Sinai, well ahead of the time that they had been anticipated to be there.

The combination of high-pressure water to dislodge and separate the particles of a soil/sand layer can be combined with the active suction from a modern vacuum truck, in what is now being called hydro-excavation. By removing the soil and water as the excavation is made this stops water from entering the walls of the excavation and leaves them relatively dry – thus resolving one of the problems that the Egyptian army encountered after their holes had been made. At the same time, by using smaller jets at higher pressures and moving them much faster the excavation rates can also be increased, with lower water volumes, so that narrow trenches can be excavated without the need for support, where rapid access is needed. But I will talk about those applications in a separate post.

*Okrimenko, V.A., "Hydro-Monitor Operator in Coal Mines and Pits", State Scientific Technical Press of Literature on Mining, Moscow, 1962, pp. 264 (Translation U.S. Army Foreign Science and Technology Center, Document AD 820634, 1967).
**London Sunday Times, December 16, 1973, p. 33

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Wednesday, March 26, 2014

Watching Iceland

Those of you who have visited this site for a while will know that I have this rather odd curiosity about Icelandic volcanoes, and more specifically the Myrdalsjokull site that sits next to Eyjafjallajokul in southern Iceland. The Icelandic site that monitors earthquakes is one I glance at fairly regularly. It has been an interesting site to visit this winter, since – more than in most years – the island has been relatively quiescent. Except that there has been this fairly consistent activity along the southern part of the rift, running roughly from Reykjavik east to Myrdalsjokull. I bring it up again today just because the sequence of earthquakes has again moved along that fault line and ended at the glacier.

Figure 1. Recent earthquake activity in Iceland (Icelandic Met Office )

Nothing big is happening immediately, just that the whole movement along this southern wing, suggests that, in time, there will be a switch to the north-south element, and at that time the stress on the corner, where we know there has been some magma movement, might prove – as they say – earth shattering!! But this is geological, where time is on a different scale than most of us.

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Tuesday, March 25, 2014

Tech Talk - Natural Gas, China and Russia in the post-Crimea time.

The recent takeover of Crimea by Russia has given China a strengthened hand as it continues to negotiate with Gazprom over the supplies of natural gas for the next few years.

It was not that long ago that Gazprom was riding high around the world, as it supplied large quantities of its own and Turkmen gas to Europe, and was negotiating to sell more into China and Asia in general. Then Turkmenistan and China arranged their own deal, and with the construction of a direct pipeline between the two countries, suddenly the market was no longer running entirely Gazprom’s way. They could no longer mandate that Turkmenistan take the price that they offered at the time that Russia controlled all the pipelines that carried the gas to market. And with that change, and the changing natural gas market, so Gazprom’s fortunes have started to teeter.

At the same time the anticipated Russian market in the United States, which would have been supplied from newly developed Russian Artic reserves such as those in the Shtokman field are no longer needed, as the American shale gases have come onto the market in increasing quantities. The world has, in short, become a somewhat less favorable place for Gazprom and the Chinese have hesitated to commit to a further order of natural gas, in part because they anticipate getting a better deal for the fuel than Gazprom would like them to pay.

Russia would like, and is anticipating, that the deal for some 38 billion cubic meters/year of natural gas, starting in 2018 will be signed when President Putin visits China in May. (In context Russia, which supplies about 26% of European natural gas, sends them around 162 bcm per year). Negotiations over the sale of the gas have dragged on for years, having first started in 2004 but the major disagreement continues to be over price. At a time when Norway is seeing a peak in production and Qatar is moving more of its sales to Asia, Russia had seen an increase in European sales, and has been able to move that gas at a price of $387 per 1,000 cubic meters (or $10.54 per kcf/MMBtu. The price of such gas in the US is quite a bit cheaper.

Figure 1. Natural gas prices in the United States. (EIA )

Russia would like to get a price of around $400 per kcm ($10.89 per kcf) with the slight extra going to pay for the pipeline and delivery costs. Whether the two countries can come to an agreement on the price may well now depend on how vulnerable Russia really is to any pressure on its markets from other sources of natural gas. Japan, for example, is now considering re-opening its nuclear power stations, as the costs for imported fuel are having significant consequences on their attempts at economic growth.

Similarly there is talk that the United States may become a significant player on the world stage by exporting LNG as it moves into greater surplus at home, thereby providing another threat to Russian sales. Part of the problem with that idea comes from the costs of producing the gas, relative to the existing price being obtained for it, and part on the amount of natural gas viably available. Consider that, at present, some of the earlier shale gas fields, such as the Barnett, Fayetteville and Haynesville are showing signs of having peaked.

Figure 2. Monthly natural gas production from shale fields (EIA)

While production from the Marcellus continues to rise, there is some question as to whether the Eagle Ford is reaching peak production although that discussion, at the moment relates more to oil production. However given that it is the liquid portion of the production that is the more profitable this still drives the question.

And in this regard, the rising costs of wells, against the more difficult to assure profits is beginning to have an impact on the willingness of companies in the United States to invest the large quantities of capital into new wells that is needed to sustain and grow production. A recent article in Rigzone took note that the major oil companies are rethinking their strategies of investment, with some reorganization of their plans in particular for investment in shale fields. This raises a question for the author:
Another question for the industry is who will supply the risk capital for exploratory drilling, both on and offshore, if the majors pull back their spending? Onshore, for the past few years, a chunk of that capital has been supplied by private equity investors who have supported exploration and production teams in start-up ventures. They have also provided additional capital to existing companies allowing them to purchase acreage or companies to improve their prospect inventory. Unfortunately, the results of the shale revolution have been disappointing, leading to significant asset impairment charges and negative cash flows as the spending to drill new wells in order to gain and hold leases has exceeded production revenues, given the drop in domestic natural gas prices. Will that capital continue to be available, or will it, too, begin demanding profits rather than reserve additions and production growth?
Before investors put up the money for new LNG plants they need to be assured that there will be a financial return for that investment. Given that it takes time for such a market to evolve, and given the need that Russia has to sustain its market and potentially to increase it, the volumes that the US might put into play are likely to be small, with little other than political impact likely.

If Russia recognizes this, and feels relatively confident that Europe must continue to buy natural gas from Gazprom, particularly with the current move by Europe away from other sources of fuel such as coal, then they are likely to be more resistant to bringing the price down for their Chinese customers. On the other hand if China thinks that it might be able to get a better deal from Iran, were sanctions to ease, or from other MENA countries, then – thinking perhaps that Russia needs the sale more – they might toughen their position and the price debate may continue.

It will be interesting to see if it resolves within the next few weeks, and if so, at what a price.

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Wednesday, March 19, 2014

Waterjettting 19b - California gold mining

While mankind has directed the flow of water against earth and rock faces for millennia, as a way of eroding and removing material, it was not until the days of the Gold Rush in California around 1850 that the idea of confining the water into a hose, and through a nozzle crystallized.

Gold was originally found in the gravel in 1848, when James Marshall was helping John Sutter build a sawmill on the banks of the South Fork of the American River, in what is now Coloma, CA.

Figure 1. Sutter’s Mill on the American River (Replica by California Parks ).

The news that gold had been found in the tailrace led into what has been referred to as the greatest mass movement of people in the Western Hemisphere, as people flocked to California over the next few years, during the period of the California Gold Rush.

Figure 2. Location of Coloma, CA (red circle) relative to Sacramento and San Francisco – Lake Tahoe is by the 395 sign in the upper right. (Google Earth)

As the prospectors panned the gold from the stream beds, so they moved north east along the valleys and rivers, seeking the sources of the gold particles that millennia had washed down from the Sierra Nevada. One such source was found at American Hill, just north east of Grass Valley. Here the gold was found in beds of a weak sandstone, lying relatively close to the surface.

Figure 3. The American Hill Diggings, with plaque. The original height of the hill can be seen in the background.

The gold settled to the bottom of the sandstone, and so the miners would tunnel into the side of the hill, seeking to find the richest layer. Unfortunately as you dig out the bottom of a hillside, the overlying rock has a habit of falling down, with mildly fatal results to those caught in its path. This made mining somewhat dangerous, given the soft nature of the rock as Edward E. Matthison found when he was nearly buried when he was working the property. So with partners, he decided that a more remote method of digging out the gold was needed. So, with the help of a local blacksmith named Miller, he fashioned a nozzle on the end of a canvas hose he ran from a water reservoir at the top of the cliff (initially a nail keg) and used the resulting stream to wash the ore (and overlying rock) into a channel that was later turned into a flume, with a series of strips to catch the gold.

Figure 4. Early hydraulic mining

The method had many advantages since, in the process of washing the rock from the solid it was broken down into individual particles. This separated the gold, sand and clay particles, so that while the gold particles would be trapped in the flume, the lighter sand and clay particles would be carried further downstream with the water. By 1853 they were paying a water bill of $153 a week (with water at $0.75 per miners inch this meant they were using 2,000 gal/min) but making the four partners a profit of $50 a day. Larger and larger monitors (the name given to the nozzle and pivoting assembly) were built, throwing water at greater distances, and mining at much faster rates.

Figure 5. Monitors at work at the North Bloomfield mine.

This, in turn, required increasing amounts of water, and this was carried in flumes down through the Sierra Nevada, with agreements being made between companies for distribution, collection and the passing on of water. The nozzle diameters of some of the larger monitors grew to more than 8 inches, and they were capable of mining tens of feet from the operator.

Figure 6. Later design of monitor. The wooden beam usually had a box holding rock on the other end in order to balance the weight of the nozzle section.

The nozzles were made longer, as they were made larger, in order to get the jet to throw to greater distances, but this made steering and control of the jets more difficult. The gooseneck swivel was invented in 1855 to help swivel the nozzle, and a monitor operator noted that when he stuck his shovel into the stream of water it deflected the nozzle. This was Dave Stokes at the Malakoff mine and led to the invention by his Supervisor, Henry Perkins, of the rotating system for sprinklers that is still used to this day.

Figure 7. Modern rotating sprinkler showing the deflection plate. (Aliexpress )

The largest mine in the region was the Malakoff, and in the region around it there were some 425 companies operating and, between 1871 and 1880 they produced $121 worth of gold (at the price of the day).

But there was costs to this operation outside of just the mining ones. For while the gold was captured in the flumes, the sand, and more particularly the clay, was carried in the water until it became less turbulent. And that was when it reached the Yuma, American and Beam rivers flowing out of the Sierra Nevada and down towards Sacramento. As the water slowed, so the clay precipitated out, and the river beds filled with sediment. Thus, when the rains came, the water overflowed its banks, flooding the neighboring fields.

Foregoing the fact that it was the mining that had brought the farmers and many others to the region, the floods were not acceptable, and following the floods of 1880 there was an increasing effort to contain the mining sediments. This led to the court ruling by Judge Sawyer in 1886 restricting the practice of hydraulic mining, and the technology fell into abeyance. It was restarted at the time of both World Wars, but in recent times there was only one small mine that had been “grandfathered” still in production. Its role in developing California is not greatly recognized at present, and the remaining legacy is more seen in the vertical bluffs and large flat areas of mined sand that are left north of Grass Valley, together with the old wooden water flumes that still thread their way around the edges of the valleys.

Figure 8. View of the Malakoff Diggings

I’ll talk more about the spread of the technology next time.

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Sunday, March 16, 2014

Tech Talk - Of wood, coal, the UK and Bangladesh

Ice and snow have returned to the central part of Missouri, so the warm heat from the tile stove is again keeping us comfortable. For many folk, however, this is not an option and they rely on a centralized power station to supply the electricity that is a fundamental part of current Western life. Yet there are moves to use more wood, even there. In an earlier post I had written that Missouri S&T was switching from a coal:wood mix to a geothermal network which, with the use of natural gas, is expected to provide a net saving of about $1 million a year on the fuel bill. Price, while important to a university, is not, however, always the controlling factor when governments get involved.

The rising prices and obscurity of future government policy has stopped progress toward a wood-fired power station in Northumberland. A plan to replace coal with wood at Blyth has reached an impass, with RES ceasing work on the biofuel plant. The $500 million, 100 MW plant had been scheduled to come on line in about two-and-a-half years but has been stopped due to “ongoing uncertainty in UK energy policy.”

On the other hand the largest UK coal-fired power plant, at Drax in Yorkshire, is in process of changing from being a coal-based plant to one that burns wood. But not just any wood, for as David Rose notes the new fuel will be wood pellets, grown and processed in North Carolina and then shipped at an ultimate rate of 7 million tons a year to the UK. The current wholesale market price for power is around $83 per MW/hr relying heavily on coal, but the agreed price for the wood-powered electricity will rise to $174 per MW/hr, higher than that of either onshore wind or the new nuclear power coming on line. (Using $1.66 per English pound). Retail prices are somewhat higher.

Price may not be that critical in the UK, but it remains critical in poorer parts of the world, such as Bangladesh, where the nation needs to infuse power into a country that has, at the moment, only a single power plant. Yet this is not a move without criticism. A recent Op-Ed in the NYT, protested the intent of the government of Bangladesh to begin a program that will develop their coal reserves. The article comes after the government appointed a new minister for Power, Energy and Mineral Resource who has pledged a new coal policy “within the shortest possible time” and it is this (and the existing 2010 policy) which has irritated Joseph Allchin who wrote the opinion.

The major concern at present deals with the Rampal coal plant which will consume some 4.5 million tons of coal a year and generate 1,320 MW of electrical energy. The coal is presently anticipated to come from either Australia, South Africa or Indonesia and is intended to address the acute shortage of power in Bangladesh, with the government aiming to raise power generation from 5,000 MW in 2011, through 7,000 MW in 2013 to 22,000 MW by 2016, that being on its way to a capacity of 39,000 MW by 2030. By 2021 it is anticipated that 14 GW will be generated from coal-fired power, with domestic coal producing 6 GW, and imports powering 8 GW of capacity. The concern comes from the nearness of the coal-fired plant to the Sunderbans mangrove forest, and the threat which this poses. But given that millions of folk live within ten miles of coal-fired power plants around the world (the closest the plant will be) the dangers seem overhyped and unrealistic.

Figure 1. Relative location of the proposed power plant at Rampal and the Sunderbans (Yale)

A second power plant of similar size (1,200 MW) will be built at Matarbari although that will also rely on imported coal, at least initially (sourced from Indonesia, Mozambique, Australia or Canada) and
The government has also a plan to implement three mega coal-fired power plants at Moheshkhali each having capacity to generate 1200MW electricity under private sector or joint venture deals.
. Domestic coal production will require considerable growth in production, given that it was only at around 800,000 tons per year in 2011. The coal coming from the thick seams of the Barapukuria coal deposit has some 200 M tons of reserves, and is being won using longwall top caving, which simplistically involves undercutting the coal thickness with a shearer, and then allowing the overlying coal to fall into the mining opening.

Figure 2. Schematic showing the idea of Longwall top caving, there is a second conveyor at the back of the roof support to carry away the broken coal as it feeds down over the back of the support (University of Wollongong )

Bangladesh has struggled for years with less than half the country having access to electricity and with the rest of the population relying on biomass and waste to provide fuel for heating and cooking. But just to keep up with current demand it must increase natural gas supplies by 35% to overcome current shortages, and thus, to meet the demand for those without power they have chosen to go with the coal-fired option.

It will be interesting to see how the politics of this unfold, given the obvious benefits that will arise as more folk in Bangladesh are provided with electricity, with all the benefits that this entails, and which is being held up by those that one might have thought would have wished to see such progress.

In passing it might be noted that China approved an additional 15 coal mines with a total output of more than 100 million tons last year.

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Thursday, March 13, 2014

Waterjetting 19a - a little history

A small personal introduction – some fifty-odd years ago I was about to graduate with a BSc degree from the University of Leeds and was then offered the option of going on for a doctorate. Since this was a Mining Department they had a number of different options that I could have followed, but I discussed this with my father, who was responsible for mechanization of one of the National Coal Board areas, and chose to study the development of high-pressure waterjets as it applied to mining.

The technology was in an extremely early stage of its development at the time in the West, although as I rapidly learned, there were already major uses for the technology in what was then the USSR. And so, with a laboratory that contained a small Uraca 9,500 psi, 4 gpm pump, I began a study that led to a lifetime career.

Some of the early things that I learned came to be adopted throughout the industry, and some of the lessons quietly disappeared. But I thought it would be interesting to go back to some of that work, particularly tying in the work done around the world in the cutting of coal and rock, so that some of these lessons could become clearer, remembered and passed on.

I was fortunate that Leeds was close to the National Lending Library at Boston Spa, and thus we came to an agreement that should I need any of the foreign papers (particularly those in Russian) not otherwise available, that they would machine translate these for me, and then we would put them into technical English. (Not nearly as easy as it sounds since computational power was relatively at about the level of an abacus relative to the standards of today).

In the beginning we were much more focused on the work that the Russians had carried out in cutting rock, although once I came to Rolla that relatively rapidly switched over into studying the work done on the mining of coal. However it may make the story more easy to follow if I begin with a return to the beginning and then work through the use in coal mining and follow that through into rock cutting.

Just after I began this series I wrote about the early work in what is now the country of Georgia where the native inhabitants were collecting gold in flumes lined with sheepskins that they hung in trees to dry – only to have a bunch of Greek thieves led by some guy called Jason, come along and steal them. They had used the natural force of streams to erode away the valuable ore deposits and carry the debris down streams and into the flumes. This idea was then developed by the Romans. After weakening and breaking gold ore in Spain through fire and gravitational collapse, they used a diverted stream to carry the broken ore out into flumes, where again the gold could be captured.

It has been said that after the Fall of Rome and the following Dark Ages that it took the world over a thousand years to get back to the technological levels that the Romans had achieved (the example of concrete is often used). In a sense this is also true of what is now known as hydraulic mining, since the practice largely fell off the scene until the use of Hushing was resurrected in the UK. The technique involves storing water behind a dam and then rapidly releasing it in a torrent to wash out and carry ore and overlying cover away down into prepared flumes. The area around such mines (found in the Yorkshire dales) is characterized by the deep channels cut into the ground by the water flow.

Figure 1. The region above the mine at Bunton in Swaledale, where hushing was used to expose and erode the mineral veins. (My Learning )

These mines date back to the early 1800’s while earlier reported work in Cornwall (based on the use in the North) in about 1500 was not apparently as successful and led to some loss of life. But that reference does indicate that the practice was already in use in Yorkshire, although there are few records to describe it before the citation above.

And so the first lesson to learn is that, if you hit a body (in this case rock and the overlying soil) with enough total force and water volume, that the target will erode and be carried away by the water flow. This is something that is evident whenever there is a severe storm along a coast around the world. See, for example, the following sequence of photos of the coastal highway near Ocean Beach CA in 2010.

Figure 2. Wave erosion of the highway near San Francisco (USGS )

In this case the shoreline was eaten back a distance of some 184 feet. And each winter we are shown the evidence of waves eating away at the foundations of houses built too close to an eroding cliff wall.

Yet it was not until the gold-rush days in California following the discovery at Sutters Mill on the American River in 1848, that large-scale water volumes were first used for the removal of not only the soil overlying the gold, but also the removal and disintegration of the gold-bearing sandstone beneath. And that is the story that I will tell next time. Although I will close with a description form that time of Sutter's Fort.
Ten miles from the river we passed Sutters fort, an old looking heap of buildings surrounded by an high wall of unburnt brick, & situated in the midst of a pleasant fertile plain, covered with grass and a few scattering oaks, with numerous tame cattle & mules. We walked by the wagon & at night cooked our suppers, rolled our blankets around us & lay down to rest on the ground, with nothing but the broad canopy of the heavens over us & slept soundly without fear or molestation.
For those not in the know Sutters Fort is to be found in the heart of downtown Sacramento.

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Tuesday, March 11, 2014

Tech Talk - Arthur Berman talks to OilPrice

One of the great concerns that I have expressed in the pieces I write here relates to the high decline rates, and increasing costs of fossil fuel extraction from oil shales. Just recently Oilprice discussed this with Arthur Berman, and have allowed me to reproduce the interview here. Since Arthur is more articulate than I on this subject I am glad to do so. Almost on a daily basis we have figures thrown at us to demonstrate how the shale boom is only getting started. Mostly recently, there are statements to the effect that Texas shale formations will produce up to one-third of the global oil supply over the next 10 years. Is there another story behind these figures?

Arthur Berman: First, we have to distinguish between shale gas and liquids plays. On the gas side, all shale gas plays except the Marcellus are in decline or flat. The growth of US supply rests solely on the Marcellus and it is unlikely that its growth can continue at present rates. On the oil side, the Bakken has a considerable commercial area that is perhaps only one-third developed so we see Bakken production continuing for several years before peaking. The Eagle Ford also has significant commercial area but is showing signs that production may be flattening. Nevertheless, we see 5 or so more years of continuing Eagle Ford production activity before peaking. The EIA has is about right for the liquids plays--slower increases until later in the decade, and then decline.

The idea that Texas shales will produce one-third of global oil supply is preposterous. The Eagle Ford and the Bakken comprise 80% of all the US liquids growth. The Permian basin has notable oil reserves left but mostly from very small accumulations and low-rate wells. EOG CEO Bill Thomas said the same thing about 10 days ago on EOG's earnings call. There have been some truly outrageous claims made by some executives about the Permian basin in recent months that I suspect have their general counsels looking for a defibrillator.

Recently, the CEO of a major oil company told The Houston Chronicle that the shale revolution is only in the "first inning of a nine-inning game”. I guess he must have lost track of the score while waiting in line for hot dogs because production growth in U.S. shale gas plays excluding the Marcellus is approaching zero; growth in the Bakken and Eagle Ford has fallen from 33% in mid-2011 to 7% in late 2013.

Oil companies have to make a big deal about shale plays because that is all that is left in the world. Let's face it: these are truly awful reservoir rocks and that is why we waited until all more attractive opportunities were exhausted before developing them. It is completely unreasonable to expect better performance from bad reservoirs than from better reservoirs. The majors have shown that they cannot replace reserves. They talk about return on capital employed (ROCE) these days instead of reserve replacement and production growth because there is nothing to talk about there. Shale plays are part of the ROCE story--shale wells can be drilled and brought on production fairly quickly and this masks or smoothes out the non-productive capital languishing in big projects around the world like Kashagan and Gorgon, which are going sideways whilst eating up billions of dollars.

None of this is meant to be negative. I'm all for shale plays but let's be honest about things, after all! Production from shale is not a revolution; it's a retirement party.

OP: Is the shale “boom” sustainable?

Arthur Berman: The shale gas boom is not sustainable except at higher gas prices in the US. There is lots of gas--just not that much that is commercial at current prices. Analysts that say there are trillions of cubic feet of commercial gas at $4 need their cost assumptions audited. If they are not counting overhead (G&A) and many operating costs, then of course things look good. If Walmart were evaluated solely on the difference between wholesale and retail prices, they would look fantastic. But they need stores, employees, gas and electricity, advertising and distribution. So do gas producers. I don't know where these guys get their reserves either, but that needs to be audited as well.

There was a report recently that said large areas of the Barnett Shale are commercial at $4 gas prices and that the play will continue to produce lots of gas for decades. Some people get so intrigued with how much gas has been produced and could be in the future, that they don't seem to understand that this is a business. A business must be commercial to be successful over the long term, although many public companies in the US seem to challenge that concept.

Investors have tolerated a lot of cheerleading about shale gas over the years, but I don't think this is going to last. Investors are starting to ask questions, such as: Where are the earnings and the free cash flow. Shale companies are spending a lot more than they are earning, and that has not changed. They are claiming all sorts of efficiency gains on the drilling side that has distracted inquiring investors for awhile. I was looking through some investor presentations from 2007 and 2008 and the same companies were making the same efficiency claims then as they are now. The problem is that these impressive gains never show up in the balance sheets, so I guess they must not be very important after all.

The reason that the shale gas boom is not sustainable at current prices is that shale gas is not the whole story. Conventional gas accounts for almost 60% of US gas and it is declining at about 20% per year and no one is drilling more wells in these plays. The unconventional gas plays decline at more than 30% each year. Taken together, the US needs to replace 19 billion cubic feet per day each year to maintain production at flat levels. That's almost four Barnett shale plays at full production each year! So you can see how hard it will be to sustain gas production. Then there are all the efforts to use it up faster--natural gas vehicles, exports to Mexico, LNG exports, closing coal and nuclear plants--so it only gets harder.

This winter, things have begun to unravel. Comparative gas storage inventories are near their 2003 low. Sure, weather is the main factor but that's always the case. The simple truth is that supply has not been able to adequately meet winter demand this year, period. Say what you will about why but it's a fact that is inconsistent with the fairy tales we continue to hear about cheap, abundant gas forever.

I sat across the table from industry experts just a year ago or so who were adamant that natural gas prices would never get above $4 again. Prices have been above $4 for almost three months. Maybe "never" has a different meaning for those people that doesn't include when they are wrong.

OP: Do you foresee any new technology on the shelf in the next 10-20 years that would shape another boom, whether it be fossil fuels or renewables?

Arthur Berman: I get asked about new technology that could make things different all the time. I'm a technology enthusiast but I see the big breakthroughs in new industries, not old extractive businesses like oil and gas. Technology has made many things possible in my lifetime including shale and deep-water production, but it hasn't made these things cheaper.

That's my whole point about shale plays--they're expensive and need high oil and gas prices to work. We've got the high prices for oil and the oil plays are fine; we don't have high prices for the gas plays and they aren't working. There are some areas of the Marcellus that actually work at $4 gas price and that's great, but it really takes $6 gas prices before things open up even there.

OP: In Europe, where do you see the most potential for shale gas exploitation, with Ukraine engulfed in political chaos, companies withdrawing from Poland, and a flurry of shale activity in the UK?

Arthur Berman: Shale plays will eventually spread to Europe but it will take a longer time than it did in North America. The biggest reason is the lack of private mineral ownership in most of Europe so there is no incentive for local people to get on board. In fact, there are only the negative factors of industrial development for them to look forward to with no pay check. It's also a lot more expensive to drill and produce gas in Europe.

There are a few promising shale plays on the international horizon: the Bazherov in Russia, the Vaca Muerte in Argentina and the Duvernay in Canada look best to me because they are liquid-prone and in countries where acceptable fiscal terms and necessary infrastructure are feasible. At the same time, we have learned that not all plays work even though they look good on paper, and that the potentially commercial areas are always quite small compared to the total resource. Also, we know that these plays do not last forever and that once the drilling treadmill starts, it never ends. Because of high decline rates, new wells must constantly be drilled to maintain production. Shale plays will last years, not decades.

Recent developments in Poland demonstrate some of the problems with international shale plays. Everyone got excited a few years ago because resource estimates were enormous. Later, these estimates were cut but many companies moved forward and wells have been drilled. Most international companies have abandoned the project including ExxonMobil, ENI, Marathon and Talisman. Some players exited because they don't think that the geology is right but the government has created many regulatory obstacles that have caused a lack of confidence in the fiscal environment in Poland.

The UK could really use the gas from the Bowland Shale and, while it's not a huge play, there is enough there to make a difference. I expect there will be plenty of opposition because people in the UK are very sensitive about the environment and there is just no way to hide the fact that shale development has a big footprint despite pad drilling and industry efforts to make it less invasive. Let me say a few things about resource estimates while we are on the subject. The public and politicians do not understand the difference between resources and reserves. The only think that they have in common is that they both begin with “res.” Reserves are a tiny subset of resources that can be produced commercially. Both are always wrong but resource estimates can be hugely misleading because they are guesses and have nothing to do with economics.

Someone recently sent me a new report by the CSIS that said U.S. shale gas resource estimates are too conservative and are much larger than previously believed. I wrote him back that I think that resource estimates for U.S. shale gas plays are irrelevant because now we have robust production data to work with. Most of those enormous resources are in plays that we already know are not going to be economic. Resource estimates have become part of the shale gas cheerleading squad's standard tricks to drum up enthusiasm for plays that clearly don't work except at higher gas prices. It's really unfortunate when supposedly objective policy organizations and research groups get in on the hype in order to attract funding for their work.

OP: The ban on most US crude exports in place since the Arab oil embargo of 1973 is now being challenged by lobbyists, with media opining that this could be the biggest energy debate of the year in the US. How do you foresee this debate shaping up by the end of this year?

Arthur Berman: The debate over oil and gas exports will be silly.

I do not favor regulation of either oil or gas exports from the US. On the other hand, I think that a little discipline by the E&P companies might be in order so they don't have to beg the American people to bail them out of the over-production mess that they have created knowingly for themselves. Any business that over-produces whatever it makes has to live with lower prices. Why should oil and gas producers get a pass from the free-market laws of supply and demand?

I expect that by the time all the construction is completed to allow gas export, the domestic price will be high enough not to bother. It amazes me that the geniuses behind gas export assume that the business conditions that resulted in a price benefit overseas will remain static until they finish building export facilities, and that the competition will simply stand by when the awesome Americans bring gas to their markets. Just last week, Ken Medlock described how some schemes to send gas to Asia may find that there will be a lot of price competition in the future because a lot of gas has been discovered elsewhere in the world.

The US acts like we are some kind of natural gas superstar because of shale gas. Has anyone looked at how the US stacks up next to Russia, Iran and Qatar for natural gas reserves?

Whatever outcome results from the debate over petroleum exports, it will result in higher prices for American consumers. There are experts who argue that it won't increase prices much and that the economic benefits will outweigh higher costs. That may be but I doubt that anyone knows for sure. Everyone agrees that oil and gas will cost more if we allow exports.

OP: Is the US indeed close to hitting the “crude wall”—the point at which production could slow due to infrastructure and regulatory restraints?

Arthur Berman: No matter how much or little regulation there is, people will always argue that it is still either too much or too little. We have one of the most unfriendly administrations toward oil and gas ever and yet production has boomed. I already said that I oppose most regulation so you know where I stand. That said, once a bureaucracy is started, it seldom gets smaller or weaker. I don't see any walls out there, just uncomfortable price increases because of unnecessary regulations.

We use and need too much oil and gas to hit a wall. I see most of the focus on health care regulation for now. If there is no success at modifying the most objectionable parts of the Affordable Care Act, I don't suppose there is much hope for fewer oil and gas regulations. The petroleum business isn't exactly the darling of the people.

OP: What is the realistic future of methane hydrates, or “fire ice”, particularly with regard to Japanese efforts at extraction?

Arthur Berman: Japan is desperate for energy especially since they cut back their nuclear program so maybe hydrates make some sense at least as a science project for them. Their pilot is in thousands of feet of water about 30 miles offshore so it's going to be very expensive no matter how successful it is.

OP: Globally, where should we look for the next potential “shale boom” from a geological perspective as well as a commercial viability perspective?

Arthur Berman: Not all shale is equal or appropriate for oil and gas development. Once we remove all the shale that is not at or somewhat above peak oil generation today, most of it goes away. Some shale plays that meet these and other criteria didn't work so we have a lot to learn. But shale development is both inevitable and necessary. It will take a longer time than many believe outside of North America.

OP: We've spoken about Japan's nuclear energy crossroads before, and now we see that issue climaxing, with the country's nuclear future taking center-stage in an election period. Do you still believe it is too early for Japan to pull the plug on nuclear energy entirely?

Arthur Berman: Japan and Germany have made certain decisions about nuclear energy that I find remarkable but I don't live there and, obviously, don't think like them.

More generally, environmental enthusiasts simply don't see the obstacles to short-term conversion of a fossil fuel economy to one based on renewable energy. I don't see that there is a rational basis for dialogue in this arena. I'm all in favor of renewable energy but I don't see going from a few percent of our primary energy consumption to even 20% in less than a few decades no matter how much we may want to.

OP: What have we learned over the past year about Japan's alternatives to nuclear energy?

Arthur Berman: We have learned that it takes a lot of coal to replace nuclear energy when countries like Japan and Germany made bold decisions to close nuclear capacity. We also learned that energy got very expensive in a hurry. I say that we learned. I mean that the past year confirmed what many of us anticipated.

OP: Back in the US, we have closely followed the blowback from the Environmental Protection Agency's (EPA) proposed new carbon emissions standards for power plants, which would make it impossible for new coal-fired plants to be built without the implementation of carbon capture and sequestration technology, or “clean-coal” tech. Is this a feasible strategy in your opinion?

Arthur Berman: I'm not an expert on clean coal technology either but I am confident that almost anything is possible if cost doesn't matter. This is as true about carbon capture from coal as it is about shale gas production. Energy is an incredibly complex topic and decisions are being made by bureaucrats and politicians with little background in energy or the energy business. I don't see any possibility of a good outcome under these circumstances.

OP: Is CCS far enough along to serve as a sound basis for a national climate change policy?

Arthur Berman: Climate-change activism is a train that has left the station. If you've missed it, too bad. If you're on board, good luck.

The good news is that the US does not have an energy policy and is equally unlikely to get a climate change policy for all of the same reasons. I fear putting climate change policy in the hands of bureaucrats and politicians more than I fear climate change (which I fear).

The interview was with James Stafford of, and I am grateful for the chance to reproduce it. Arthur Berman writes at Petroleum Truth Report.

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Wednesday, March 5, 2014

Waterjetting 18d - Abrasive considerations

It would be best if, before I ended this short session on abrasive, I mentioned some of the practical constraints that sometimes limit the options for choosing abrasive types. To give a simple example, we were, at one time, demonstrating the ability of a waterjet drill to penetrate limestone. In the demonstration that morning we had used garnet as the abrasive and had made a steady penetration down to about 70-ft but the contracting office on the project did not seem overly impressed. So, after lunch, I suggested that we switch to an aluminum oxide abrasive, since we knew it was more aggressive.

Unfortunately for the afternoon program we were using a DIAjet type of system, where the abrasive is added to the water under pressure just downstream of the nozzle, and upstream of the delivery nozzle. While that worked well with the garnet abrasive (which passed without significant damage through the swivel on the end of the drill) that was not the case with the aluminum oxide. This is a much sharper abrasive and less prone to damage in mixing. As a result once we had the rig back in operation we were immediately struck by the black color of the water coming out of the hole – as the aluminum oxide stripped the inner lining from the hose carrying it to the nozzle. We then watched as, in real time, the pressure gage on the driving pump slowly slid back from the 10 ksi initial pressure to about 2 ksi as the abrasive ate out the orifices of the nozzle. Needless to say, having pretty much destroyed the downstream equipment in about five minutes, the afternoon demonstration was a bit of a disaster.

I also remember the first time that we used steel shot to try and cut through some rock, without giving too much thought to encasing the cutting operation. Those small spheres retained a lot more energy than most particles, and we were dodging the equivalent of shotgun pellets which ricocheted around the lab as we raced to shut the system down.

Both abrasives are, in their place, very effective tools in cutting materials that might be more difficult or uneconomic to cut by other means, but the peculiarities of their nature require that special precautions be used when they are used to make sure that there are not unintended consequences.

Sometimes the choices are simply practical. When we were cutting the walls of the Omnimax theater under the Gateway Arch in St. Louis, where we had to cut straight down (within half-an-inch either way over 15-ft of cut depth) through dolomite and chert it took less than a day to realize that the cost of using garnet to achieve the 12 – 15-inch individual cut depths was going to drive us out of economic reality within a week. Changing to a blasting sand (which we bought by the ton) did not change the cutting performance by much, but had a remarkable effect on overall costs.

Figure 1. Effect of abrasive type, size and feed rate on the depth of cut and optimal cutting condition when cutting rock. (after Yazici*)

Abrasive type and abrasive size both effect the depth of cut, and thus the economics of a cutting operation. Yet it is not possible to draw absolute rules since the different abrasives have different relative cutting efficiencies in different materials. For example, in the above plot boiler slag was relatively ineffective in cutting rock. On the other hand, with the right type of slag and steel Faber and Oweinah** have reported that slag can cut steel more than three times as efficiently as garnet. (This is partly because the slag shatters on impact and the fragments go on to scour the uplifted edges of the cavities generated by the initial impact of the particle.)

And while the British Welding Institute use smaller particles to cut softer materials, they have found it critical to use larger particles to get viable performance as the target material gets harder. In cutting steel I had mentioned in an earlier post, that garnet becomes less effective at a particle size below 100 micron. Yet in cutting aluminum (which is softer) the particles can be smaller and yet still effective.

Figure 2. The effect of particle size when cutting aluminum using corundum particles (after Faber and Oweinah ibid)

Yet, as discussed at the beginning, the cost of the abrasive must not only be set off against the potential for improving the cutting rate, one has to also look and see if there is an increase in the operating cost of the system when a harder, and thus often more effective cutting abrasive is used. Zaring et al showed this with a plot that they published at the 6th American Waterjet Conference***.

Figure 3. Relative benefits and costs of changing abrasive type (after Zaring et al***)

All things are, however, relative, and in some small cutting operations we have found it more economic to sacrifice the nozzle over the cutting time required in order to achieve a cut that could not be effectively achieved any other way.

As with many things in the waterjet business, while there are general rules that can be laid down to guide operations, when it comes to specific cases then it is often worth running a small series of tests on the projected target material, using different abrasives, at varying size ranges and feed rates, before calculating (usually using a normalized cost in dollars or gms per area of cut) the most effective abrasive for a given operation.

*Yazici, Sina, Abrasive Jet Cutting and Drilling of Rock, Ph.D. Dissertation Mining Engineering, Univ. of Missouri- Rolla, Rolla, MO, 1989, 203 pp.
**Faber, K., Oweinah, H., "Influence of Process Parameters on Blasting Performance with the Abrasive Jet," paper 25, 10th International Symp Jet Cutting Technology, Amsterdam, Oct, 1990, pp. 365 - 384.
***Zaring, K., Erichsen, G., Burnham, C., "Procedure Optimization and Hardware Improvements in Abrasive Waterjet Cutting Systems," 6th American Water Jet Conf, Houston, TX, Aug, 1991, pp. 237 - 248.

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Monday, March 3, 2014

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.

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