Oil up, gas down, and Hurricane season is here

I had meant to include the weekly plot of gasoline demand in the last post, that began by talking about the hybrid, but somehow the post drifted into a different direction and I ended up not including it. The graph, from this week’s TWIP, showed that gasoline demand is really remaining fairly constant at a rate slightly above last year(and in about the same relatively flat condition), though you might want to recognize the significant difference in price. This time last year was about the time that price peaked.
Gas demand over the past year (EIA TWIP)
Gas prices over the last two years (EIA TWIP)

The question on where it goes from here does depend on the way the global economy goes, though as you gather, in the case of gasoline, with the spread between supply and demand now controlled by OPEC, I expect that there will be a slow but steady increase.

Natural gas, on the other hand is another story. The Natural Gas Weekly (NGW) report is out today, and shows the slow but apparently inexorable decline in prices is continuing.

Natural gas prices against oil prices (EIA Natural Gas Weekly)


This steady decline in gas prices, which may well continue if there is the influx of LNG at year end, has the potential to significantly hurt the developing production of natural gas from the gas shales. As I previously noted, Chesapeake may well be able to produce from these formations at less than$4 a tcf, but once the price gets down to $3 or so, then I suspect that those bets are off.

The NGW is not very comforting in that regard, noting that

At $3.41 per MMBtu on Wednesday, July 29, prices at Henry Hub were $9.17 per MMBtu, or 63 percent, below last year’s level at this time. Current spot prices at market locations in the lower 48 States average about 62 percent below year-ago levels.

As a result there has been a further increase in storage injection, significantly above the 5-year average figures. The NGW blames this on the unseasonably cool temperatures:

Relatively mild temperatures in each of the Census Divisions in the lower 48 States during the week ended July 23, 2009, likely contributed to the above-normal level of injections into storage. Based on the National Weather Service’s degree-day data, temperatures in the Lower 48 States during the week were, on average, more than 2 degrees cooler than normal and 4 degrees cooler than last year’s levels.

Whether this has anything to do with the lack of sunspots, and the consequent slight drop in received sunlight is a topic for another day. (If the colder weather continues into the winter, then the drop in demand for air conditioning may be compensated by the increased need for heat). Though the stubborn refusal of the global temperature to follow the steadily increasing curve that has been predicted by the AGW models is becoming remarkable.

That difference with prediction is also evident from the subject of the TWIP front page this week, which dealt with the amount of oil from the Gulf of Mexico (GOM) that gets shut in each season due to hurricanes.

Impact of Hurricanes on GOM production (EIA TWIP)

The slow decline in overall production is partly because of the loss of smaller and older producers following recent major hurricanes – production too small to justify the redrilling of wells, and also it is because the fields near the coast are well defined and exploited, and are in overall decline. But the risks from hurricanes are clear, when the platform locations are examined.

6357 oil platform locations in the GOM

The question that the TWIP asks relates to the likelihood of there being strong and frequent hurricanes through the platform-intense regions this season. So far, with the cooler relative sea temperatures there has not been the activity of more damaging years, but the TWIP quotes NOAA as predicting a slightly higher than normal season, with a consequent transient outage of 4.5 million barrels over the season. However the recent identification of this as being an “El Nino” year may change that prediction, though we won’t know until next week, August 6th to be precise.

Whether storms are increasing in severity has been a subject of debate, following such a prediction in “An Inconvenient Truth” , but the data apparently does not show that there has been an increase in storm energy but rather the reverse.

Historic trends in Cyclone Energy (Ryan Maue )

And, as far as oil and gas production from the Gulf is concerned it is only going to take one strong hurricane with the wrong path and, as historic experience has shown, production can be really impacted. (It took years to get the Thunder Horse platform back into commission after it was damaged by Hurricane Dennis in 2005, and the 250,000 bd of oil and 200 mcf of gas production temporarily lost).

The season is yet young, and we’ll just have to wait to see what transpires.

New cars, miles travelled, crude oil and Charles Gibson

Over the past three weeks we have driven to Maine and back, putting 3,000 miles on the new Fusion Hybrid and, in the process averaging some 39 mpg, with times where we got over 41. I think that it is just a little better in that regard than the Camry Hybrid we drove out in last year. And, since it calculates the distance you can travel on a tank of gas based on the average achieved, seeing a 650 mile reserve after a fill-up is quite nice. As I mentioned earlier the trunk space in the Ford is a little smaller than the Camry, and the GPS system is not quite in the Magellan or Garmin class though generally effective.

But that gets me back into my consideration as to where things are going, and a continuation of the thoughts I posted recently on the future of crude prices. I remain somewhat optimistic about where the economy is going to go. There is some evidence that house prices are starting back up a little according to the S&P/Case-Shiller index. This holds true not only in the USA but also in the UK. The numbers are sufficiently small that perhaps we should only recognize the halt in declines, rather than the hope of a continuous upturn, yet it is a start.

On the other hand the upturn in vehicle miles driven that started in April has continued with a y-o-y increase of 0.1% in May. Looking at the 12-month rolling total there is even the hint of an upturn there.

Moving 12-month total of travel on all roads (FHWA)

So what will that do to gas prices? Demand isn’t really changing that much overall for gasoline in the USA, and I really didn’t think that Charles Gibson’s “Over a Barrel – the Truth about Oil”, last Friday, was that obviously enlightening in trying to answer that question. (But if you read between the lines . . . .)


He found that gas stations make more money from their convenience store products than from gas; that all gas regardless of brand usually comes from the same pipeline, in the same truck to all the local dealers; he found that there had been no new refineries in the past 30-years, though smaller ones had closed and others had grown larger;

There are 149 refineries in the United States, 26 fewer than there were in 1995. And the top 10 oil companies control close to 80% of the country’s refining capacity.

But oil industry leaders say that was a necessary business decision in a competitive market. “The smaller, less efficient refineries really couldn’t compete in that environment. They did shut down, so we had a lot of falloff in the industry,” said Rayolda Dougher, a spokesperson for the American Petroleum Institute. “And you are right. If you had overcapacity and you are not able to sell your product at a profit. You are going to have to cut back on that capacity. But look over time, and look at the record and you will see that capacity has grown.”

The ABC report noted that while demand for gasoline has risen 15%, refinery capacity has only grown 14%. But it also pointed out that a major driver on price of product coming out of the refinery is tied to the cost of the crude going into it. And so the story moved to look at both domestic supply (the “drill, baby, drill” argument) and that available from overseas. It quoted Vijay Vaitheeswaran of the Economist, that most of the remaining world reserves of oil lie in Saudi Arabia, Iran, Iraq, Kuwait and the UAE. And the Secretary of Energy was then recorded saying that this condition promised us a “train wreck.”

To see whether this dependence on foreign oil (70% of U.S. supply) could be switched around, the crew visited the Chevron platform in the Blind Faith field 160 miles out in the Gulf. The platform is producing 65,000 bd of crude and 55 mcf of natural gas. But while this individual effort is an indication of where future supply must come from, it will not be enough to satisfy demand.

The report concluded with a remark by T. Boone Pickens suggesting that if all the areas that could be drilled around the nation were drilled and started production, that the total gain in production would only be about 2 mbd. He then pointed out that the US imports 13 mbd. We cannot break our addiction to oil by trying to drill our way of the shortfall in domestic supply.

And so the report ended with the note that gasoline, given all its travels, processing and other costs, is still a relative bargain at $2.50, because there is no recognition of the hidden costs. It really did not draw the logical conclusion that the future strength of the US economy is tied to the benevolence of those five Middle Eastern countries, nor how rapidly that dependence will become evident again. But if you wanted to read between the lines, that message was there, hidden behind the realization that domestic supply alone cannot rescue us from our situation.

Now the actual broadcast covered more ground than is given in the write-up. The good Dr Yergin made an appearance at Cushing, OK talking about the pipelines and the basis for the common established price for crude at that place. And there was some discussion of the role of speculators in driving up the price, but the underlying message remained as the written report notes, that we are heading into trouble – pity it was so well concealed.
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Drilling with diamonds

Today I am going to talk about diamonds, and how re-making them can produce a much better drilling bit. Last tech talk I briefly reviewed how a tri-cone bit worked. These are the bits that are used in most oil wells, and while they crush the rock immediately under the bit teeth their most productive work comes in creating chips from the rock between two adjacent tooth indentations by a combination of wedging and uplift that breaks the rock under tension and shear.
Simplistic view of bit tooth penetrating rock.

As the bit is pushed into the rock it crushes the rock immediately under the tooth, and this crushed rock distributes the applied force around the edge of the zone as it plastically deforms. This gives the lateral and upward forces on the surrounding rock that causes it to crack and spall from the solid as a chip.

There is, however, a problem, in that some rock is too hard to be able to push the tooth into the rock and create a big enough crushed zone to do much good with conventional materials. So, obviously, the next step is to go to a harder bit material. And to make sure that we can cut into the hardest rock material, it is logical to want to use the hardest material, diamond, for the bit tooth. Historically, however, finding and being able to afford diamonds in the sort of half-inch size we need for the bit tooth was a bit difficult. The ones that were affordable were the very small diamonds known as industrial diamond, in the very small sizes. So the way in which we had to cut the rock was changed. Instead of having a few teeth that rotated over the surface of the rock, instead the face of the bit was coated with a thin layer of small diamonds set in what is called the matrix.

Diamond coring bit, the dark specks are individual diamonds (Source)

The very small diamonds scratch into the surface of the rock, in the same way that a diamond in a ring might cut into a glass plate. Individually the scratches are small, but if the core bit is pushed into the rock, they accumulate and remove rock, although quite slowly. A tri-cone bit might go through rock over 100 ft an hour, a conventional diamond bit which is taking much smaller bites, will go at only a few feet an hour. It also turns faster than a conventional bit, which is why they are often combined with a down-the-hole motor on the bottom of the drilling string to give this faster speed.

And if you push too hard on the bit, then you can push the diamonds down into the matrix, so that the matrix is rubbing against the rock, rather than the sharp diamond edge, and this slows things down. (This is particularly a problem if drilling through granite, which I once spent a summer doing). And so the question came as to how to make this sort of drilling faster. We would still need the diamonds, to cut into the harder rock, but couldn’t we find a better way of making an artificial diamond – after all we only need to have it on the surface of the bit, and perhaps just apply it as a coating to a bit.

Well it turns out that this was possible, and depending on which convention you adopt the Polycrystalline Diamond Compact (PDC), or the PolyCrystalline Diamond (PCD) was born. Simply put (and the technology is actually anything but) a thin layer of diamond power is put into a mold and a central core of tungsten carbide is then nested in the middle of the mold. The mold is then put into a special press where the assembled powder is subjected to extremely high pressure and temperature, using specially designed anvils. Temperatures are in the 2,000 oC range, and pressures around 60,000 bar (882,000 psi). The result is an element (they come in a variety of shapes) where the carbide bit is coated with a thin layer of a polycrystalline diamond, since all the diamond particles have fused together to form the surface layer.

(In reality the technology is a bit more complex, since a single thin layer of diamond is brittle in the way the shell of an egg is, without strong back support, and so there are graded layers to make this “diamond” shell tougher so that it does not shatter when it hits the rock hard).

The most typical shape that is used in oil and gas well drilling is a small cylindrical insert, with the bit made up of a number of these individual cutters.

Individual PDC cutters. The dark portions are the diamond coated segments (Source).

There was a considerable effort put into designing the best way of combining these cutters, back during the last Energy Crisis, with a lot of the work being done at Sandia Labs. The bits that have emerged are now much larger and more robust, and are quite widely used. Energy Tomorrow featured a picture of one back in May.
Large drill bit combining the buttons of a tri-cone (the silvery points) with polycrystalline diamond cutters (the dark circles). (Source)

Notice that the diamond cutters are along the edge of the rigid parts of the drill bit. This is because the diamond, although a very powerful cutter, is very sensitive to temperature. Since the cutter is being dragged over the surface plowing up and peeling off a slice of the rock, there is a lot of friction under the cutting point, and if the cutter heats up above about 300 degrees then it softens, which is not good. So by placing it on the face of the bit, and with an open passage to the face, cooling mud (of which I will write more next time) can now flow across the face of the cutter, keeping it cool, and thus sharp, and able to cut through all the rock in the way. (If you were to look at the full face there are more cutters in the center of the bit and along the edge to make sure that none of the cutters is asked to cut too much – remember that the whole bit is turning, so the cutters on the outside also move faster over the rock).

This type of cutter is now large enough that can now cut deeply enough into the rock that it can chip some of the rock out ahead of it and so the process also becomes a little more efficient. (But I will revisit that topic when I talk about the energy of different rock drilling methods in a later post).

One of the reasons that the support for the cutter is so long is that the edge of the cutter is pushed into the rock, and still has to crush the rock under it, to get enough purchase to be able to chip out the rock ahead of it. (Though one that starts less rock has to be crushed as the bit moves forward).
Schematic showing how dragging a PDC cutter across a rock surface will crush the rock under the bit, and then create a chip as the cutter gets under the rock ahead of it.

As usual with these tech talks, I have simplified the description in order to keep this short and to the point. If those knowing more wish to comment, please do so.

Energy Shortages, the Monsoon, India and Pakistan

The international impacts from a lack of sufficient power are often missed when debate swirls about the price of oil and gas, and the need to control emissions as part of an effort to change climate dynamics. There is a site, Energy Shortage, which provides information on the different parts of the world where energy shortages are occurring, both as short-term events, such as the power outage in Belize over the weekend a week ago, (though with more forecast) and the longer term problems that I have discussed before with power shortages between demand and supply. This impacts countries such as India which currently has a gap of between 15,000 and 20,000 MW between what is needed and what is available. Pakistan is currently seeing both problems, a short-term (though now over 48-hours) blackout in Karachi, because of torrential downpours due to the monsoon, and a longer term national shortage of more than 3,000 MW .

Part of the problem in this part of the world is that it relies on the rains of the monsoon season to provide hydroelectric power. Thus far, in India, the monsoon has not been strong, though the converse is the case in Pakistan, as the situation in Karachi demonstrates. There the rain has been sufficient to restart operations at one of the hydroelectric plants, that at Mangla, which is producing 220 MW, and expects to double that in a few days. Overall the national picture has improved over the last year, it being reported that while the overall shortfall was 4,633 MW last year, the drop to the current levels shows a significant improvement. Thus load shedding of 10 – 12 hours last year, has fallen to 8 – 10 hours this year.

But in India the rains are late and have been, until recently, weak.

It has been a heart-breaking June, with the fabled wet wind from the southwest absent in most regions normally on its itinerary. The northern plains are bone dry, with temperatures regularly touching the mid-40s in centigrade. They are the last port of call for the complex, mobile weather system which usually arrives there in July after drenching the vast swathes of peninsular India in June. But the monsoon has not even kept this date, for a number of reasons. . . . . . . By the end of June, the rains were estimated at 54% below normal levels in these parts, with the deficit reaching 75% in central India . . . . . . According to data collected since the 1940s, "normal" is 890 millimeters for the whole season.

The impact on the country is still developing

After the predictions were made public, the first knee-jerk reaction came from Punjab. The state banned the use of air-conditioners in government offices, boards and corporations - despite the sweltering heat - so eight hours of uninterrupted power could be supplied to the farm sector. . . . . The monsoon, which runs from June through September, is such a big thing in India that a bad year has the potential to topple governments. Even now, 60% of Indian farmland is dependent on rains, not irrigation. It goes beyond the economic, the imprint goes into the very socio-cultural make-up of a nation.

It is, however, not only food production that is now threatened

For instance, the Tehri hydroelectric power station in Uttarakhand supplies power to New Delhi and its hinterland. The water level in its reservoirs has shrunk to dangerously low levels - 741 meters against a normal level of 830 meters during monsoons. The Bhakra dam, the biggest hydroelectric project in northern India, has water flowing in from the mountains. Its reservoir levels remain lower than they were last season.

The problems extend to Bangalore, which is the hub of much of the IT in India, but where the situation is little better

Monday saw the worst power situation so far since the start of the monsoon in early June. Two hydroelectric power stations stopped generation for a few hours to conserve water and one unit of the thermal power station at Raichur in north Karnataka tripped, plunging many areas in Bangalore and the state into darkness in the evening.

Added to the misery of Bangaloreans was a sudden downpour, accompanied by heavy winds, lightning and thunder which too disrupted connections in many areas of the city.

That heavy rain marked the onset of what many are now hoping will be a regular series of rains that will provide the water that the nation needs. However the rains have come over a month late and this is a problem since the monsoon provides up to 80% of India’s rainfall. The hope is that when the season is over the shortfall may be as little as 7% of the average, with serious concern only arising if the shortfall rises to 20%.

It is however, not just with rain that the country is beginning to fall short. More than half of India’s power generation comes from coal, and the stocks for the power plants are reportedly down some 50% from normal.

NEW DELHI, July 13 (Reuters) - Coal stocks with power plants in India halved from normal levels to 11 million tonnes at July 6, with many thermal plants facing uncomfortable supply positions, junior power minister Bharatsinh Solanki said.

He said 31 power stations had a critical supply condition, having a coal stock of less than 7 days, and of these 10 plants were "supercritical" having a coal stock of less than 4 days.

It is light of this situation that the recent friction reported between Secretary Clinton and the Indian Government must be born in mind. India intends to construct something on the order of 78.7 gigawatts of new power plant in the next five years, much of which will be fueled by coal. The country needs the power, and there is little other than coal that can be expected to meet this demand. As a result there was the following report

A July 19 event intended to showcase cooperation on clean energy technology at a “green” building outside New Delhi spotlighted the debate. The Indian environment minister said India resents demands from the U.S. for adoption of legally binding caps on carbon emissions.

“There is simply no case for the pressure” considering India produces among the lowest per capita emissions in the world and 500 million of its citizens have no access to commercial energy, Minister Jairam Ramesh told Clinton during a closed-door discussion that a reporter was allowed to observe.

Let us hope that the monsoon brings enough rain that this ends up being a problem that the Indian government does not have to think about in the next three months.

The basic method for drilling through rock

There are times when new technologies are proposed as being better ways of drilling for oil and natural gas. However, to understand how these are better (or more likely not) than existing technologies, you have to know how the industry commonly drills through rock. There are two basic ways of doing so, depending on how hard the rock is. The first is the one that made the Hughes family very rich (if you ever saw the film The Aviator, Howard Hughes extravaganzas were paid for because his father had invented an effective way of drilling oil wells). The other, somewhat slower, was developed the last time that we had an energy crisis, and uses artificial diamonds, in the main, to gouge into and scrape off thin layers of rock.

I am going to borrow a bit from a post I made at TOD four years ago, this week, to explain a little about how the first one works, and then come back in a week or so to describe the idea behind the other one. Starting therefore with the Hughes bit, which, for reasons that I will explain, is usually referred to as a tri-cone bit.
The three cones of a tricone bit

To start one can go back to the mining industry (can we call it one of the older professions) where holes were drilled, until about a hundred years ago, by taking a chisel in one hand and holding a hammer in the other with which one whacked the upper end of the chisel as it was held against the rock. This is called hand steeling and if you want to try it or see it, there is a video here and student competitions at various places. A skilled miner can drill a 1-inch hole at the rate of about 8 inches in five minutes, using a 4-lb hammer.

Now what he does (if you watch the video you will see this) is to hit the chisel, turn it about a quarter turn between blows, and then hit it again. The turning is the critical bit. Because when you hit the chisel it crushes the rock directly underneath it, but the wedge head pushes sideways against the rock on either side. So if the driller turns the chisel between blows he will not only crush the rock, but will also chip out the thin layer between the second blow and where the first hit. This removes a lot more rock for the same amount of energy. In fact it is the skill of the driller that will make bigger chips, for less muscle power, by turning the bit, rather than using brute force to crush the rock just under the chisel into powder. (On a larger scale the same idea is used to drill very large tunnels. Bit disks roll over the surface of the rock crushing the rock immediately below them, but the rock in the inches of spacing to the next disk spalls out of the face without direct contact with the tool).

When it came time to drill the first oil wells this was the technique that they used. Except that they made the chisel much larger and heavier, so that, by lifting it and dropping it, it's own weight would act as the hammer. Normally a larger spudding bit was used first to make a larger diameter hole from 4 to 22 inches in diameter, and down for 50 ft or more. Once this starting hole had been drilled (using a cable over the derrick to a crank to raise and drop the bit) a steel pipe was lowered into the hole and cemented in place. This pipe provided a base for the deeper hole, and provided a case around it. Thus it became known as casing, and it protected the hole as it went through the top soil and weakest of the upper layers of the ground.

Once the hole had been spudded-in, and this initial conductor pipe installed, then the normal sections of steel tubes could be strung together to form a pipe (hence the name drill string), and the drilling bit (in those days around 4 to 5 inches across) would be raised and dropped by a walking beam engine. As the hole was drilled they would stop, perhaps every couple of feet, to pull the bit out, and sharpen it, and to bail the crushed rock or cuttings, out of the hole.

Progress was, as you can imagine, slow, and this tool is very difficult to steer, particularly as the drill goes down several hundred feet. And so the industry was ripe for a better way of drilling.

This was invented by the older Howard Hughes who realized that if very small chisel shapes could be set around a roller they would do the same thing as the dropping bit, but could be moved around by rolling, and pushed into the rock by the weight of the connecting rods to the surface. To spread the load over the face of the hole, and to balance the bit, he used 2 rollers which tapered towards the center of the bit.

Hughes, along with his partner Walter B. Sharp, formed the Sharp-Hughes Tool Co. and produced a model of his new bit. Rather than sell his bits to oil drillers, Hughes and Sharp opted to lease the bits on a job basis, charging U.S. $30,000 per well. With no competitors to duplicate their drilling technology, they soon garnered the lion's share of the market. Flush with their success, the partners built a factory on 70 acres east of downtown Houston, where they turned out the roller-cone bits that quickly revolutionized the drilling process.2

This later evolved into a 3-cone assembly and what is now known as a tri-cone bit, a modern version of which is pictured above. (The shape of the teeth vary as a function of the hardness of the rock that is being drilled. As a rough rule, the tougher the rock the smaller the teeth are, and the smaller the chips that are generated).

This bit has a number of problems under different conditions (it is harder to control in directional drilling since if the pushing force varies too much it can wander off in odd directions) and there has to be a way of getting the rock out of the hole. These have led to other drilling ideas, and I will discuss these, and the second “diamond bit” drilling idea in later posts.

But as you watch the movie "The Aviator" remember that all those shenanigans were paid for with the money that came from that drilling bit, and that Hughes (the company) is still reported to have 40% of the world market share of oilwell drill bits.

The Shrinking Sahara

One of the major arguments of those who argue about the perils of increased global warming is that there are almost no beneficial aspects to the transition to a warmer planet. In the process they therefore often ignore news that argues to the contrary. Consider the BBC story that indicates that the Sahara might be turning greener.

It has been assumed that global warming would cause an expansion of the world's deserts, but now some scientists are predicting a contrary scenario in which water and life slowly reclaim these arid places.

They think vast, dry regions like the Sahara might soon begin shrinking. The evidence is limited and definitive conclusions are impossible to reach but recent satellite pictures of North Africa seem to show areas of the Sahara in retreat.

It could be that an increase in rainfall has caused this effect.

There is in the story the possibility that the changing climate might improve things, but the story notes

Droughts over the preceding decades have had the effect of driving nomadic people and rural farmers into the towns and cities. Such movement of people suggests weather patterns are becoming dryer and harsher.

The Intergovernmental Panel on Climate Change warned recently that rising global temperatures could cut West African agricultural production by up to 50% by the year 2020.

But satellite images from the last 15 years do seem to show a recovery of vegetation in the Southern Sahara, although the Sahel Belt, the semi-arid tropical savannah to the south of the desert, remains fragile.

To show you how wrong this picture is, relative to reality, go to the little Google box on the top right of your screen and type “record harvest sahel.” You will find the weather and crop situation reports for the Sahel The Sahel runs 2,400 miles (3862 km) from the Atlantic Ocean in the west to the Red Sea in the east, in a belt that varies from several hundred to a thousand kilometers (620 miles) in width, covering an area of 3,053,200 square kilometers (1,178,800 square miles). It is a transitional ecoregion of semi-arid grasslands, savannas, steppes, and thorn shrublands lying between the wooded Sudanian savanna to the south and the Sahara to the north. The countries of the Sahel today include Senegal, Mauritania, Mali, Burkina Faso, Niger, Nigeria, Chad, Sudan, and Eritrea. (Wikipedia)

Source Sahel Crop Report (pdf)

There was a record harvest in the region in 1999. This was succeeded by even greater production results in 2001 when Chad had a record harvest, as did the Gambia and Burkina Faso, Mali had a good harvest, and Niger one that was above average. Guinea Bissau had a reduced harvest.


In more recent years the problem has been that the cheapness of international imports has brought prices down below those of crops grown locally, together with an increase in international aid. Yet the crops that have been produced have led to bumper crops, consider last year.

DAKAR - Poor people in Africa's arid Sahel region will go without food despite bumper harvests this year, as wild price moves on world markets put staple cereals beyond many families' budgets, aid agencies say. Prices of imported foods have ballooned in recent years, pushing up prices for locally grown crops even though harvests are expected to be bigger than ever after abundant rains.

"The nature of food insecurity has changed in West Africa," Alexander Woollcombe, Food Security Advocacy Advisor at Oxfam GB told Reuters. "It's not a problem of production. The problem is, poor people can't afford to buy it."

Oxfam expects cereal production across five countries in the dry Sahel belt south of the Sahara -- Burkina Faso, Mali, Mauritania, Niger and Senegal -- will be a record 18.5 million tonnes this year, but the food on sale will be beyond the budget of many in these, some of the world's poorest countries.

And

Projections of a record grain harvest for the 2008/09 growing season are being borne out, with total output for the Sahel and West Africa estimated at 54 million MT, including 9 million MT of rice and 45 million MT of coarse grains. Grain production in the Sahel is estimated at 15, 500,000 MT,1 up 21% from last year (2007/2008) and 24% above the five-year average.

Virtually all countries in the Sahel are reporting sizeable increases in rice production. On average, output was up 34 percent in 2008/09, or more than 530,000 MT greater than that of 2007/08. Good climatic conditions and the stability of local markets reflecting similar international market trends bolstered grain production in general and rice production in particular. In addition, government incentives helped reinforce and strengthen the capacity of local farmers through specific agricultural revitalization programs, subsidies and distributions of free supplies of farm inputs, fiscal measures, etc.

Back in 2002 there was this:

New Scientist has learned that a separate analysis of satellite images completed this summer reveals that dunes are retreating right across the Sahel region on the southern edge of the Sahara desert. Vegetation is ousting sand across a swathe of land stretching from Mauritania on the shores of the Atlantic to Eritrea 6000 kilometres away on the Red Sea coast.

Nor is it just a short-term trend. Analysts say the gradual greening has been happening since the mid-1980s, though has gone largely unnoticed. Only now is the evidence being pieced together.

It has been reported that by 2002 the Sahara had been reduced in size by 300,000 sq. km. as a result of these trends, which (as the current BBC story notes) have continued.

The problems of the Sahel are those of too large a population, and the impact that reliance on overly cheap imports of food have, to the detriment of local farmers. The changes due to the climate have brought about record harvests and greater areas available for agriculture.

But those benefits will not be reported with as much vigor as the problems that the region has, and the negative aspects of climate change the BBC article, for example, suggests, contrary to the evidence, that there has yet been little improvement in the conditions. Instead they concentrate on the artificial reduction in the desert that the Egyptians are trying

Thanks to the work of people like Mr el-Baz, the greening of the desert is happening in Egypt in a controlled way.

Out of the newly irrigated desert we now see the commercial growing of oranges, limes and mangoes.

Further, the Egyptian government is actually sponsoring people to settle in the desert to farm, using the water supply they can now tap into and pump out from under the sand.

The programme is part of an ambitious and controversial plan to reclaim 3.4 million acres of desert.

In either case changes in the climate are bringing demonstrable benefits, a pity that we don’t hear more of them, or that the BBC does not read its own archives.

Crude Prices for the rest of the year

As the summer moves inexorably towards its close, debate still bubbles along on the future price of oil over the winter. Of course that brings in the question of what sort of a winter we’re likely to see, and that is also a bit controversial on the climate change front, but I’ll leave the arguments on that to the weekend. Suffice it to say that the current lower temperatures that we are seeing suggests that it is likely to be colder rather than not. If we look at the way the price of crude has varied, there are arguments which might suggest that it could go either way, over the next six months.

Crude oil price volatility.
If the world economy collapses much further then this can further reduce demand, and further slack can appear between available supply and demand. That surplus has been suggested to have the potential to be a “devastating glut”, with the potential to drive crude oil prices down to $20 a barrel. Is that likely? Well with all respect to those making such predictions, I don’t think so.

Certainly this all depends on the economy to a great extent, but we sometimes forget that this is the world economy that we are now discussing, and that there has been a general move to stimulate that economy, not just the efforts now finally starting to add money to the economy in the United States. And yes, suddenly, we are seeing some of that money appear. The pages listing opportunities for research in Energy are suddenly full of requests for proposals for very significant levels of support. And they are getting a lot of response.

The Advanced Research Projects Agency – Energy (ARPA-E) of the U.S. Department of Energy (DOE) completed the submission stage of its first Funding Opportunity Announcement (FOA) released April 27th, 2009. ARPA-E has received approximately 3,500 concept papers for the $150 million available as part of this FOA (DE-FOA-0000065).

The large number of submissions – “Concept Papers” - for ARPA-E’s initial FOA outstripped the expectations of industry observers and highlights America’s capacity for Energy technology innovation that can be applied to transformational research and development (R&D).

ARPA-E’s first solicitation is funded through the American Recovery and Reinvestment Act of 2009. The announcement is primarily aimed at prospective applicants who already have a relatively well-formed R&D plan for a transformational concept or new technology that can make a significant contribution if and when successfully deployed. Submitters of the most meritorious Concept Papers will be encouraged to submit Full Proposals. ARPA-E expects to provide responses to Concept Paper applicants by the end of the last week in July on whether a Concept is likely to form a basis of a successful Full Proposal. The deadline for Full Proposals is expected to be the end of August.

Given that illustration of the arrival of the stimulus monies by the end of the year, and presuming that it holds true also in other sectors of the economy, then there will be some cause for an underlying continuation of confidence. (As opposed to a sudden onset of fear that nothing is working). This will likely be sufficient to hold us away from a return to a collapse of the economy, and with that demand for oil and gas will not suffer much drop at the end of the driving season, and going into the heating season.

With relatively little change in demand the control on supply will reside in OPEC and given that they have been able to manage supply to get the price up to levels that they are comfortable with, I would expect that to continue. Now OPEC does not have instant control of prices, oil supplies take a certain time to get from supplier to user, and for oil to be refined, moved and sold so there will be some fluctuations, as transient imbalances along that route play into speculation and the like. Overall, however I still look to prices rising slightly through the fall.

There are, however, so many political strings to this that making a very confident statement of the future is a path paved with peril. The eventual fate of the Waxman Markey legislation may have an influence on public and industrial perception, depending on how it turns out. Further the degree of international cooperation that this Administration is able to achieve towards their goal, and in building and maintaining public confidence is going to also play a critical part.

I note, for example, that Secretary Chu is currently in China and has agreed to a joint research center on Clean Energy.

The Center would facilitate joint research and development on clean energy by teams of scientists and engineers from the U.S. and China, as well as serve as a clearinghouse to help researchers in each country. Priority topics to be addressed will initially include building energy efficiency, clean coal including carbon capture and storage, and clean vehicles. The U.S. and China together pledged $15 million to support initial activities.

However in the scheme of things, this is not a lot of money at the moment.

Rather, given the rising demand for fuel in Asia, because they are buying more cars and will drive them, and the stabilizing demand for gas elsewhere, I don’t see a sufficient drop in demand that can’t be controlled by OPEC, and I expect that they will continue, therefore to control price, for at least another year.

Highway maintenance concerns

One of the things that struck me in my recent trip to China was the vigor with which the state was driving highways (with associated tunnels and viaducts) up through the mountains to access and connect some of the more remote communities in the hinterland. It is a very expensive undertaking, and yet it reminded me of the words of a history colleague who noted that it was the development of the roads and the automobile that really opened up America and liberated a large part of the rural population and brought many benefits to the country.

I mention this because there is a quietly increasing cost that is threatening that continued access and that is likely to have a negative impact in the near future. It was the subject of today’s editorial in The Kennebec Journal under the headlines “Is Maine maintaining too many roads?” The State has 8,500 miles of road and the question has been asked:

"Is 8,500 miles too much road system for us to afford and do too many of those roads go through too rural areas of Maine, and the cost of building them to standards too high or even maintaining them, and should we just decommission a percentage of the roads?"

It is a question that is not unique to Maine, many of the more rural states with low populations are faced with the rising costs of road maintenance and the increasing price of asphalt and other repair materials, not to mention the bridges and other infrastructure. In the short term there are some funds coming from the stimulus package that might help with the odd project, but that is a “one-shot” deal that cannot hope to address the size of the problem.

"These bridges and highways serve as critical links for Maine communities, and every day that we let them fall into further disrepair costs us lost lives, lost income and lost economic potential," says economist Laurie Lachance, head of the foundation.

But one could substitute the name of a number of states and still have the sentence be true. Partly, as the article notes, the increased costs come from a previous commitment to upgrade rural roads perhaps beyond the point that usage would justify, but that being the case, has the time come to start stepping backwards? For even in more urban states, the problems are merely growing with time. Consider Michigan where a State Senator notes

For one, the federal stimulus package is bringing in $847 million in additional one-time revenue designated for surface transportation purposes. Unfortunately, state-owned highways and expressways are getting the lion's share of the funding, with our county and municipal roads receiving only a fraction.

But the federal stimulus package still presents an opportunity. Remember that the state is receiving up to $7 billion in additional federal stimulus funding over a two-year period. This could free up other state-generated revenues to be used for our infrastructure needs.

The size of the problem is, however much larger, and in the smaller communities where roads must be resurfaced, budgets are getting stretched and roads are converting back to gravel. In cities however that is not an option, and projects are being scaled back as the cost of asphalt must be met. Hope, Arkansas is an example

“About two years prior to (2005), we were paying in the range of $30 per ton,” (City Manager) Cook told the Hope City Board of Directors recently.
In a recent bid opening for hot mix to be used in this year’s street program, the City agreed to pay $114.50 per ton to low bidder Charles Lindsey, of Ashdown. The only other bid at $145 per ton was submitted by Sid and Sons, of Texarkana.

Cook admitted to a certain surprise at the disparity.
“We were projecting that asphalt might bid out as high as $130 per ton,” she said.

Rural bridges are equally a part of the problem, Missouri, for example, has more than 10,000 bridges of which more than 1,000 are in need of repair. However, outside of the stimulus, the state is funding a program, known as Safe and Sound .

Safe & Sound is a multi-faceted program that will improve more than 800 of Missouri’s worst bridges in five years. Safe & Sound will prevent many of the state’s worst bridges from being closed temporarily or permanently for safety reasons.

The program is funded through a bond program that the state runs. Other states are not that fortunate.

Of the nearly 600,000 highway bridges in the country, 24.1 percent were reported deficient and/or functionally obsolete in 2006, a minor improvement from 2005 when 25.5 were deemed deficient. At the current rate of repair it will take 62 years for today's deficient bridges to be brought up to date.

With the rising prices of repair materials both roads and bridges will need levels of funding support that is not likely to be available. Of course this is not just a problem in the Unites States, but countries around the world will continue to address the problem, and many will not have the resources of China.

So conditions, in countries such as those in Gambia, will continue to be so bad as to inhibit pregnant women from visiting health centers (for example). It is not likely that rural conditions will get that bad in America that communities become cut off in this fashion, yet the marriage of cars and highways require that both be maintained, and one is not that useful without the other. And in the end both, at the moment, depend on the availability of oil, at a reasonable price, a condition that is decreasing, again, in probability.

And lest you wonder at the pause in posts of the last few days, Owen William came into our lives, and is our first grandchild. We thus had other things on our minds.

Trying to legislate technology

Over on Climate Progress there is a note on the 100th coal-fired power station to be cancelled or postponed in recent months. This one is in Utah, and was cancelled as a result of the decision of the City of Los Angeles to be “coal free” by 2020. The Intermountain Power Agency was going to build a third power station, some 900-megawatts, to meet LA’s growing needs, but this is not to be.

Los Angeles Mayor Antonio Villaraigosa announced last week that the city -- which purchases about 45 percent of the IPA's power -- wants to end its use of coal-fired power by 2020. Villaraigosa said that the city will replace its coal-fired electricity with energy from renewable sources, natural gas, nuclear and hydroelectric power.

It will certainly be interesting to watch how this plays out, given that the best wind sites in the state appear to be already in use, and that there has been a slowdown in growth of new farms, to the point that Iowa has now passed California by. Certainly Baja California is getting into the act, with the promise of having 75% of the power needed for public lighting to come from a wind farm by 2011. But there is a considerable difference between the 10-megawatts of that plant, and the 900-megawatts just foregone. Solar continues to be very much more expensive, nuclear is unlikely to be available within the time frame anticipated, and there has been some debate about dismantling dams that provide some of the hydroelectric power. So it will fall on the back of natural gas to make up the shortfall, or so it would appear.

This would seem to give additional impetus to the prospects for the Ruby pipeline.

As proposed, the Project is expected to include approximately 675 miles of 42-inch natural gas transmission pipeline, beginning at the Opal Hub in Wyoming and terminating at interconnects near Malin, Oregon. Contracts for the pipe have been signed and pipeline construction companies have been selected. The Project will have an initial design capacity of up to 1.5 billion cubic feet per day (Bcf/d) and will traverse portions of four states: Wyoming, Utah, Nevada, and Oregon. Four compressor stations are proposed for the project: one near the Opal Hub in southwestern Wyoming; one south of Curlew Junction, Utah; one at the mid-point of the project, north of Elko, Nevada; and one in northwestern Nevada.

The connection of a pipeline from the currently underpriced supplies in Colorado and Utah into the Western market through the connection in Oregon and into the Northwestern gas pipeline will likely reduce the costs of gas in the West, while giving Colorado and Utah markets for their gas, at the time that they are potentially losing the Eastern market that was targeted with the Rockies Express. That pipeline has now reached Ohio and was placed to meet the need for cheaper gas in the North East. (among other things by replacing Canadian gas, which is also now going to lose the market in California). This market is now threatened by the potential of gas supplied from the Marcellus shale.

The role that hydrofracing plays in all this provides an interesting sub-text. As I have recently noted, there is a move by two Coloradan Congressmen and one from New York to tighten the regulation of hydrofracing. However
industry officials claim state regulation of the practice is more than adequate and that the chemicals used in fracking need to be kept secret for competitive purposes.

They also argue that in 60 years of fracking there has never been a case directly linking it to the contamination of drinking water wells because so many precautions are taken.

Interestingly Colorado has recently passed tougher legislation governing drilling in the state, which includes the need to list the components of the fracing fluid, legislation which is said to have increased costs in the state, and reduced the level of drilling (albeit the price of gas might just also have some effect on this).

The desire by the Colorado Congressfolk to make the rest of the nation work to the same rules as their gas industry (which incidentally does not have that much of the gas shale which requires hydrofracing to be economic) has yet to be decided in the national Congress, but should the legislation pass then the costs to the California consumer may be significant.

Unfortunately, at the time that they discover that the costs of switching to the more environmentally friendly power generation system is costing them significant dollars (at a time when California is broke) it may be too late to reverse the decision, in the way that Durango recently did and move back to coal, since the coal plants will not, it would appear, now be there.

Whether, with the increasingly levels of demand for natural gas to replace planned coal-fired plants, the natural gas will be there to meet that increased demand is a tale for another day.

(NOTE: When I originally wrote this piece it had a different end section, the original end section, and the reason for the change are discussed in the section below. My apologies for the error in including that material, and my thanks to Gail for catching the error and drawing my attention to it).


. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
When I first wrote this piece, the end segment read as follows:
The role that hydrofracing plays in all this provides an interesting sub-text. As I have recently noted, there is a move by two Coloradan Congressmen and one from New York to tighten the regulation of hydrofracing. The fight is now, apparently getting a little rougher. (H/t Prof Goose) A research professor at Colorado School of Mines has run into some unpleasant reactions.

Thyne said he was threatened with termination as a research associate professor at Mines, a position he still holds through the end of the summer, because of pressure put on the state school by powerful players in the oil and gas industry who were upset with his position that federal regulation of hydraulic fracturing may ultimately be necessary if oil companies don’t find other solutions.

In fact he has moved on to another university (Wyoming) but has been working on a site where there is a possible problem.

Thyne contends there needs to be much more rigorous study of fracking to determine the extent to which it can contaminate groundwater supplies. Industry money currently being poured into the aggressive and highly defensive campaign to defeat DeGette’s legislation would be better spent building a credible scientific case for why the exemption was necessary in the first place, he adds.

Industry officials claim state regulation of the practice is more than adequate and that the chemicals used in fracking need to be kept secret for competitive purposes. They also argue that in 60 years of fracking there has never been a case directly linking it to the contamination of drinking water wells because so many precautions are taken.

But Thyne is currently being employed as an independent consultant by Garfield County to study a case near Silt in which a property owner claims fracking contributed to an ongoing gas seep in Divide Creek.

Interestingly Colorado has recently passed tougher legislation governing drilling in the state, which includes the need to list the components of the fracing fluid, legislation which is said to have increased costs in the state, and reduced the level of drilling (albeit the price of gas might just also have some effect on this).

As for the CSM prof, given that the story has popped out only after he had found a position to move on to, I tend to be a bit cynical about the weight of the pressure that might have been applied to him. Having been peripherally involved in a case of our own where a faculty member’s untimely remarks about a company to the press probably cost our University at least one and likely several large contracts, as well as ruining relations between us for several years. It happens. There were several rude exchanges, so I gather, but it all blew over. As this likely would have.

But given the desire by the Colorado Congressfolk to make the rest of the nation work to the same rules as their gas industry (which incidentally does not have that much of the gas shale which requires hydrofracing to be economic) I am not sure that the overall discussion will have as simple an outcome.

. . . . . . . . . . . . . . . .
The reference to Dr. Thyne is innaccurate. It turns out, as Gail discovered and called to my attention that CSM had commented on the situation, with the following statement:

“I want you to know that no one in the Mines administration recalls having anything but cordial conversations with Dr. Thyne this spring. When Dr. Thyne was quoted during that time by the media, the school received inquiries about Dr. Thyne’s association with Mines.

“As a result, Mines officials phoned and e-mailed Dr. Thyne to inform him of the inquiries, and also to remind him of the university policy that people must be clear in public communications that the opinions they express are personal and do not represent institution positions — one way or another — on issues being discussed.

“Also, as a matter of clarification, Dr. Thyne left employment at Mines in August 2006 due to employment at the University of Wyoming. He has remained in a very limited role on a non-paid basis (in an advisory capacity with graduate students) since then, and that contract ends at the end of August 2009.”

Given the dates at which Dr Thyne changed employment, it appears, therefore that there is significantly less to the story than I had described. My thanks again to Gail for catching this, and my apologies that I did not.

Problems for the Pickens' Plan

It is a relatively cool, overcast day here in Cambridge, MA, a little damp and after yesterday being chased up the New York Thruway by a storm carrying hail and cutting visibility to yards, (and the Fusion getting 41.6 mpg), only the occasional tree moved in an almost still day. Which is to suggest that it is not a good day for the prime candidates promoted as the sustainable fuels of tomorrow, here in the North East. That does not stop the tourists, however, and I noted as we came back to the hotel earlier this evening, that it was full and turning folk away. (Though it was easier for us to get rooms this year than last, and it is now offering a premium for those that stay over a weekend, and is giving away Internet services, neither of which held true last year).

The larger blow to the sustainable energy story today, however, is not the chill of an autumn day in July in Massachusetts, but rather the colder stillness of the lack of movement by Boone Pickens on his wind farm in Texas. The reasons for the turn around depend on who you read. The Wall Street Journal notes

Mr. Pickens, who has spent the last year pushing his "Pickens Plan" to reduce the nation's dependence on foreign oil, said the wind farm project was scuttled in part because of the lack of adequate transmission lines to carry the electricity from remote locations to cities. He had hoped to build new transmission lines but ultimately was unable to secure financing.

while Daily Finance noted the problems of raising money

Pickens, 81, was undaunted declaring at press conference on Capitol Hill, "I didn't cancel it ...Financing is tough right now and so it's going to be delayed a year or two."

"Cancel" may not be the right word. How about review? Pickens, who gained fame as a corporate raider in the 1980s, was planning to build the world's largest wind facility, at a site in the windy, flatlands near Pampa, Texas, which would generate enough electricity to power about 1.2 million homes.

The initial problem that Mr Pickens faces is that he has ordered the turbines and “like I said, my garage won't hold them," the legendary Texas oilman said. "They've got to go someplace."

There are 687 turbines involved, each to produce 1.5 MW of power and the question of where to put them, given that there are problems with the initial siting due to the need for connection to the grid, is likely to be a challenge. The problems have been visible for some time. Back in November there were signs that the credit crunch was hurting the program, and the drop in natural gas prices (which were the other half of the coin) has meant that there is no rationale for changing from natural gas to wind at the present time.

On the other hand, back this time last year the Texas legislature approved putting in the connections to bring the wind power into the grid.

Texas regulators have approved a $4.93 billion wind-power transmission project, providing a major lift to the development of wind energy in the state.

The planned web of transmission lines will carry electricity from remote western parts of the state to major population centers like Dallas, Houston, Austin and San Antonio. The lines can handle 18,500 megawatts of power, enough for 3.7 million homes on a hot day when air-conditioners are running.

The project will ease a bottleneck that has become a major obstacle to development of the wind-rich Texas Panhandle and other areas suitable for wind generation.

The transmission lines are needed since, at present, there is more capacity than can be delivered through the existing grid.

"When the amount of generation exceeds the export capacity, you have to start turning off wind generators" to keep things in balance, said Hunter Armistead, head of the renewable energy division in North America at Babcock & Brown, a large wind developer and transmission provider. "We've reached that point in West Texas."

Unfortunately that plan, shortly thereafter, ran into the Justice Department. The initial idea had been to integrate a water pipeline into the right-of-way so that Mr Pickens could also pipe water to Dallas and the water-short folk in East Texas from his holdings in West Texas.

At the time, Mesa General Counsel Bobby Stillwell said the company "got too clever."

Said Stillwell: "We had thought that doing them jointly would be a convenience and maybe even a cost savings to us and the landowners. There were two things that we misjudged. To do that we would have to acquire a 250-foot right of way instead of just a 150-foot one for electricity. That was enough difference to the landowners," he said. "Secondly, they were criticizing the whole project, both water and electricity, when they were really concerned about water. We didn't want both to be subject to the same criticism."

And so, last September, the water pipeline idea was scrapped, then the plan to use the wind power to displace natural gas was also put aside, and now the idea of the large wind farm itself has had to be laid aside.
But

Pickens continues to buy up water rights and says he expects to build smaller wind farms in Texas, as well as in Oklahoma, Kansas, and Wisconsin. He's still hopeful about his hedge funds, too.

This is occurring just as the President is sending out a team to encourage rural America to become involved in sustainable energy. It is not the best juxtaposition of events to see the sales pitch for wind included in their statements.

Wind energy offers rural landowners a new cash crop. Although leasing arrangements vary widely, royalties are typically around $2,000 per year for a 750-kilowatt wind turbine or 2% to 3% of the project's gross revenues. Given typical wind turbine spacing requirements, a 250-acre farm could increase annual farm income by $14,000 per year, or more than $55 per acre. In a good year, that same plot of land might yield $90 worth of corn, $40 worth of wheat, and $5 worth of beef." (Original Blogger's note: This report and its numbers are 5 years old. I've heard of lease payments of $5,000 per turbine.)

So just as I thought that wind was taking the commanding lead in the alternate energy stakes, we have days like today. Such events are bound to slow the growth of alternative fuels to the fossil fuels we now use, which makes the ongoing concern about the long-term viability of supply of those fuels ( worrisomely summarized by Sam Foucher at TOD) that much grimmer news.
.

A gentle cough toward the New York TImes

The NYT sees the current movements in oil prices as being extremely volatile, with “no signs of slowing down.” This implies that the world can expect that not only will prices rise above current levels, but that they can equally well drop to levels down around $30 a barrel.

In my own mind, accepting there is some transience in price, given not only the variations we are now seeing in demand because of the global slowdown in the economy, but also because of the time factor in moving supplies, the market has much less volatility and much greater rationality in performance than it is being given credit for.

Starting with the collapse of the oil price last year, and with demand dropping due to the recession the world was, transiently, in a period where there were was a significant surplus of production. But as that became evident, so OPEC moved to cut back production, so that the dramatic drop in price that signified over production was only transient in nature. At the time OPEC commented that an oil price in the $65 - $75 range would be a fair one, and one that they could live with. It would appear that they now have sufficient control of the market that they can achieve, and hold that price. However that only holds true for the short term.

It is being increasingly accepted that non-OPEC producers cannot, overall, further increase their production, and that, instead, from this point forward, non-OPEC supplies will decline, albeit in the short term only slowly.
Thus control of the supply moves to OPEC, and by cutting back on supply, to match demand, they were able to stabilize, and then gradually force an increase in the price, to a level that they remain comfortable with. I expect that, over the next year, they will be able, by adjustments in supply, be able to sustain the balance and thereby stabilize the price of crude at levels they are comfortable with. As I noted recently there are some indications that the drop in demand for transportation fuel has reached bottom, and is picking up, not only in the United States, but with the increases in vehicle numbers in China and India, also globally.

Unfortunately, the ability of OPEC to further increase supply, bringing their production back to the highest levels of 2008, will not potentially, be able to overcome the decline in non-OPEC production for long – even though we are talking about differences of only on the order of 1 mbd. Because as soon as that inequality re-establishes then I fear we will be back to the rising prices of oil that take it beyond OPEC control since they will be unable to pump the additional oil needed to hold the supply adequate to demand.

When will that occur, at present the leaves are too difficult for me to read, but I strongly suspect that it will be before the next Presidential election. Within that time frame I suspect we also will not see the volatility that the Times anticipates, but rather (with relatively minor perturbations) a slow but inexorable rise in price

Real Climate vs Climate Science

There is a form of ongoing debate ocurring between Real Climate and Roger Pielke Sr about recent predictions in regard to what is going on with the current climate.

Basically the debate resolves around the comment

Some aspects of climate change are progressing faster than was expected a few years ago - such as rising sea levels, the increase of heat stored in the ocean and the shrinking Arctic sea ice. “The updated estimates of the future global mean sea level rise are about double the IPCC projections from 2007″, says the new report. And it points out that any warming caused will be virtually irreversible for at least a thousand years - because of the long residence time of CO2 in the atmosphere.”

Now it is an illustration of the way in which the debate is twisted that Roger Pielke begins the debate by pointing out that the conclusions drawn in that paragraph are not tenable, and provides graphic evidence to the point. (As an illustration if you look at the gradient of sea level records the most recent measurements (from the Jason satellite) have, over the time period from 2002, a shallower gradient than those from the TOPEX satellite that preceded it. (Note this is a corrected paragraph - I had written temperature instead of level, my apologies).

However, Gavin, over at Real Climate, changes the focus of the argument, from the error in the original conclusion, to interpreting the change in only the last couple of years as being a positive conclusion by Roger, and claiming that it is inaccurate because it is made over too short a period.

But the original conclusion, derived over this short time interval, is one made by the alarmists, so that, in reality the criticisms that Gavin is advancing argue against the conclusions that he is touting, rather than the criticisms of them. (Although it must be noted that the criticism that the report distorts data in its interpretation also holds true if one looks at the longer picture). It cannot be acceptable to sieze on short term changes - such as the transient drop in ice area - and accept the two-year interval over which this occured - but then deny the evidence, over the longer period, that this is purely transitory, on the criticism that the longer period is too short to allow a realistic conclusion (after drawing one from the shorter interval).

The criticism made of the conclusion that the climate changes are accelerating is not born out by the evidence, and such evidence as there is argues against the conclusions. It is a pity, therefore, that the conclusions are getting the scale of publicity and acceptance that they are.

On the Road again

Last Monday we took delivery of the Ford Fusion Hybrid, that I have mentioned in earlier posts, and we are now on our first trip driving it instead of the Camry.

For those looking at both, they are, from a comfort point of view, both enjoyable, the trunk space in the Ford is a little smaller, but given the needs of two adults not restrictively so.

One of the items that delayed our receipt of the car was that we wanted the Ford GPS system installed. It turns out that this is not quite as helpful as the Magellan that I keep in the Camry, and was a bit more expensive (it fails to lead you to the door in certain addresses) there are perhaps compensating benefits, but we will have to be further down the pike before we can identify them.

We like the collision avoidance features. They tell if someone is in your blind spot by putting a small orange light onto the right wing mirror, and the car seems to get more milage per tank, but we haven't enough miles yet to say that this is significant.

As far as anecdotes about the trip, the restaurants seem a little fuller than they have been recently and the roads a little busier, but it is early days on the trip yet, so I'll be back with more comments in a couple of days.

Hydrofracing Natural Gas Wells

Some time ago I wrote a piece for The Oil Drum on Hydrofracing, that explained some of the basic processes involved in the technology. Since then there have been the hearings by the House on the process, with concern being expressed, particularly from Members from New York, and Colorado, about the impact of the process on drinking water. So I thought I would repeat that post here, with a couple of additional opening comments.

Firstly, as I noted in my post on the Congressional Hearings there is a good Primer now available on the Web that contains a lot of the information (including the chemical composition of some of the fracing fluids) that people are concerned to get. Also, (h/t to Jane Van Ryan of API) there is a video which explains the process. Neither, however, explains that the wells typically have a relatively short life, with around 60% of well production coming that first year, a point I have posted on earlier.

To begin with it’s probably best to start with rock pressure. And to explain this I am going to do some simplification, so, as I ask in most of these “techie talks”, to those who do know better please understand that this is trying to explain concepts, but also please do comment on where I may either accidentally or by error, get something wrong.

As we go deeper into the earth, the weight of the ground above us will also increase. For a very simple measure we can assume that this is around a 1 pound per square inch (psi) increase for every foot deeper we go. So if we were, for example, 10,000 ft down then the pressure in the rock due to that weight would, undisturbed, be around 10,000 psi. (This is about 7 times the pressure that you see coming out of a car wash pressure washer for example).

When a oilwell is drilled vertically down into that rock it does not see this pressure, but it does see a part of it. The reason is that the rock on either side of the hole can now expand into the hole, and we’d rather it didn’t. (It’s somewhat as though you step on a rubber eraser – the eraser will bulge out laterally as it compresses vertically under your weight). The resistant pressure in the horizontal direction can be calculated as a function of the vertical pressure through a ratio known as Poisson’s Ratio . Sufficient for our discussion to say that can have a value of about 0.3. So that if we are 10,000 ft down, then the vertical pressure on the rock will be around 10,000 psi, and the horizontal pressure will be around 3,000 psi. If the well is vertical then the casing for the well has to be designed for the 3,000 psi level.

Now, if instead of just drilling the well vertically I turned and drilled it out horizontally through the rock, then the hole would now have the 10,000 psi squeezing down vertically, and the 3,000 psi coming in from the side. So the first thought that we have is that the casing (the lining that we put into the hole to make sure that it stays open) has to be a bit stronger. Life gets, however, a bit more complicated than that. When you put a hole into ground that is under pressure, the first response of the rock is to try and move the weight of the rock over the hole onto the rock on the sides of the hole. This roughly doubles the pressure that is on that thin layer. Before the hole was put there that particular rock was held in place by the rock around it, and collectively the mass could carry the original pressure. But now there is no rock where the hole is, and thus the confining pressure on the rock there is less. (In technical terms you have shifted the load from a triaxial confinement under 10,000 psi to a uniaxial load of 20,000 psi.) The result can be that the rock on the sides of the hole crushes under the load. This then puts crushed rock or sand into the hole, and that interferes with lots of things. Now you can possibly stop that by keeping the pressure high in the liquid that you are using inside the hole to get the drilled rock out (the drilling mud), but if you keep that pressure too high, then the oil/gas won’t flow to the well and so you have to drop it down to a certain level.

Life also gets a bit more complicated in reality, since the presence of the fluid in the rock tends to even out the pressure within it. So that while, relatively close to the surface, and in a dry rock the ratios may be as I gave them earlier, with a fluid saturated rock, and in an over-pressured region, the horizontal pressure can be as high as 80% or more of the vertical value. The values generally get closer to 100% as the wells go even deeper, but that is another story.

So rock pressure is the first problem that you have to deal with. But why do we drill the horizontal holes in the first place, why can’t we just use the old vertical ones. Well the reason is that the old ones didn’t work very well. And to explain that I am gong to try and re-explain a recent article from Penn State . (then I’ll give the relevant quote).

Shale is a very fine grained rock, and though gas can gather in the small pores of its structure, if the gas is to flow to a well, then it has to migrate through passages that are very narrow, and thus very resistive to that flow. However, as the shale has been formed under geological pressure and over time, the pressures not only compressed it from mud into shale, but they also caused it to fracture. In the Marcellus shale, for example, the cracks that occurred in the shale are roughly vertical, and form two sets that are perpendicular to one another.

The first advantage that a horizontal well has, over a vertical one, is that the well can penetrate a long way through the rock that carries the oil or gas (OG). The amount of OG that comes from the rock is, in part, a function of how long the length of well is in the rock that carries it. So that while a vertical well might produce say 800 bd from a well that goes straight through a 200 ft thick layer of oil-bearing rock, when the well is drilled so that it goes out 4 miles horizontally through the oil-bearing rock, then the production per day may go up to 10,000 barrels.

The second advantage relates to the way in which the fractures lie in the rock. Because they are vertical, a vertical well won’t hit very many of them, and so since these fractures provide an easy flow of OG to the well, rather than the difficult path through just the rock, then the well will not show very much production. (And this was the case with many of these shales when tested earlier).

However if the well is horizontal (see figure) then the well will intersect many of these fractures and in drawing the fluid from them will also provide an easy path for fluid to ease out of the rock into the fracture paths, so that the entire rock can be more easily drained.



Now in the picture I have shown one set of joints as being bigger than the other. And that is usually the case, because the horizontal pressure, that earlier I had suggested was the same in each direction, actually usually isn’t. The strongest horizontal pressure will tend to close up those fractures that run perpendicular to it, and tend to open the ones that run parallel with it. Thus it helps to know at the level of the shale, what the pressures in the different directions are (those engineering among us generally refer to them as stresses rather than pressures). The best direction to drill is then perpendicular to the maximum horizontal pressure, if we want to take the best advantage of the fractures in the rock. The only problem with this is that it also increases the pressures on the sides of the borehole, so that if we go that way, and the rock is not that strong, then we may be making the borehole stability worse.

But even with a horizontal well the production may not be that great, because the fractures are still relatively narrow, and so flow won’t be that fast. And so there is another tool that can be used, and that is to deliberately put a crack into the rock on the side of the borehole. On a very small scale, if you look at the picture, you can see a shaded zone around the vertical well. If I could make a crack out from the well at that level and grow it out just a short way you can see that it already intersects two of the better joint sets, whereas at the beginning the well didn’t reach any. And if we could do this from the horizontal well and grow that crack out a goodly distance horizontally, then it would intersect a lot of the vertical fractures and production would become high and useful.

There are, however, three snags to forming and growing that crack, all solvable, but all costing additional money. The first is that if we just grow the crack out and then let the weight of the overlying rock close it up again, then we haven’t made a whole lot of difference. So we have to prop the crack open. For this we need to inject relatively fine grained particles (let’s call it sand, though the technical term is proppant) into the crack in enough quantity that it will fill up the crack and hold it open so that it gives an easy path through the rock to the well for the OG. (We won’t go into what a mess pumping sand at more than 10,000 psi makes of the pump – Halliburton gets paid very nicely to fix those problems).

The second snag is that trying to push sand into a thin crack and get it to go very far can be an exercise in futility. Among other things if you are using plain water the sand tends to settle to the bottom rather fast, and if it fills the crack near the well, it then acts as a filter to stop sand going back further into the slot. So now we change the chemistry of the water by adding what are usually known as long-chain polymers. These chemicals thicken the water so that it will (at relatively low chemical percentages) suspend the sand in the fluid. Because these molecules are also slippery (in another variety they are added to the water in crowd control water cannons to produce what is known as Banana Water – since it makes the street too slippery to stand on) they also reduce the friction between the fluid flow and the walls of the crack, and this also helps carry the sand further back into the crack, and gives the slickwater title to the hydrofrac.

The third snag is a bit more technical. You remember that earlier on I talked about the pressure about the hole causing the sides of the horizontal well to crush. Well at the top and bottom of the well instead of the rock seeing this additional crushing pressure, the shifting of the vertical load to the walls of the hole, can mean that the rock will go into tension, where it is much weaker. As a result cracks can appear in the top and bottom of the horizontal hole. Why is this a problem? Because the easy way to cause a fracture to grow is to fill the well with liquid and increase the pressure of the liquid until the rock breaks. (Hence hydraulic fracture or hydrofrac). But if there is a crack there already then just increasing the pressure in the hole causes that crack to grow. And if the crack is vertical then it won’t grow in the horizontal direction we want. And so it is time to call in the engineers (who also don’t come cheap) to do the interesting things that cause the crack to grow in the right direction.

The benefits to all this for the Marcellus has been described by Engelder.

"Conservatively, we generally only consider 10 percent of gas in place as a potential resource," said Engelder. "The key, of course, is that the Marcellus is more easily produced by horizontal drilling across fractures, and until recently, gas production companies seemed unaware of the presence of the natural fractures necessary for magnifying the success of horizontal drilling in the Marcellus."

The U.S. currently produces roughly 30 trillion cubic feet of gas a year, and these numbers are dropping. According to Engelder, the technology exists to recover 50 trillion cubic feet of gas from the Marcellus, thus keeping the U.S. production up. If this recovery is realized, the Marcellus reservoir would be considered a Super Giant gas field. . . . . These fractures, referred to as J1 fractures by Engelder and Lash, run as slices from the northeast to the southwest in the Marcellus shale and are fairly close together. While a vertical well may cross one of these fractures and other less productive fractures, a horizontally drilled well aimed to the north northwest will cross a series of very productive J1 fractures.

You can see examples of the fracture patterns in the Marcellus here

The upfront money may give some pause to prospectors. A typical well that drills straight down to a depth of about 2,000 to 3,000 feet costs roughly $800,000.

But in the Marcellus Shale, Range and other companies hope a different kind of drilling might yield better results — one in which a well is dug straight down to depths of about 6,000 feet or more, before making a right angle to drill horizontally into the shale. That kind of well could cost a company $3 million to build, not counting the cost of leasing the land, Engelder said.

The company, in a December financial report, estimated that two horizontal wells are producing roughly 4.6 million cubic feet of gas per day. Tests on an additional three recently completed horizontal wells showed potential for a total of 12.7 million cubic feet of gas per day. Industry experts call those results promising.

The benefits have also been projected here.And while they may be considerable, it is only after the wells are in production, and not only initial flows, but also well lifetimes are established, that the true benefit will become apparent.

But until some solid, repeatable well data emerges, the Haynesville will remain more diamond in the rough than diamond ring. As BMO Capital Markets analyst Dan McSpirit rightly noted in a report last week: "The proof (of Haynesville economics) is in how the wells get drilled and the rates of return such operations yield." He added, "These are early innings. Lasting value creation should be revealed later in the game."

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So there you have a brief explanation of how the new technology is slowing, though it won’t stop, the declining gas reserve in the United States,

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