Saudi Arabian oil production, OPEC cuts and IEA estimates

It appears that the world economy has started into a slightly more significant phase of growth, at least according to Saudi Arabia. When the recession hit, in order to control prices and maintain at least a semblance of their income, the nations of OPEC instituted a cut in supplies, initially of just over 2 mbd and then, last December again, to a total of 4.2 mbd, that ate up what would have been a global surplus of oil. In that way prices could be brought back to the $65 to $80 dollar range that OPEC prefers.

Over the past few months, as the economy has improved, and oil prices began to move up again, so there has been a gradual slippage in the rigidity with which the supply was curtailed. In the first half of the year, overall the EIA estimated that OPEC was supplying some 28.7 mbd, which it reported as being some 2.6 mbd less than a year earlier. Of those sticking to the OPEC targets, Saudi Arabia has been the most rigorous. Given that it also supplies the greatest amount of crude of the OPEC nations, this also, more than other nation’s restrictions meant that the world supply could be set in balance with the perceived demand, and price controls could be maintained.

In June OPEC reiterated their position that supplies would be restricted, despite future price rises, until the existing global surplus was drawn down. However there was a report, in April, that part of the reason for Saudi’s adherence to policy might have been caused by an inability to sell more than 7.89 mbd.

The question of Saudi capabilities has been a topic of conversation ever since Matt Simmons wrote “ Twilight in the Desert,” yet if one looks at the EIA figures for crude production, Saudi Arabia had a peak in production of 9.7 mbd in July 2008, but had cut back production this year to an average (over the first seven months of the year) of 8.2 mbd, although by July they had increased back to 8.58 mbd, from a low of 8.086 mbd in February. However part of this increase is due to an increase in internal consumption, shown by the relative plot from Energy Export Databrowser. (which includes more than just the crude and distillate that the EIA counts).

Saudi Arabian oil production (Energy Export Databrowser)

The kingdom is uncomfortably aware of this burgeoning demand, and is already seeking ways to provide internal power by other means . Part of the problem has been that they have relied on natural gas to provide much of their internal power, but have discovered that in cutting back on oil production, they have also restricted the amount of natural gas produced. Which might explain their recent request that nations of the world might have to pay extra even when they don’t buy as much oil as they used to.

But those days, already seem to have passed and now, perhaps in order not to let prices start to rise too much, as the global economy appears to be regenerating and demand grows, Saudi Arabia has recognized that it can continue to increase the amount that it itself supplies, without threatening the overall price levels that have now been reached.

The amounts being made available do not fully relax the cuts that Saudi has made in production but nevertheless the removal of some restriction recognizes the change.

one Asian customer expected to receive full contracted volume for the first time in a year . . . . other lifters of crude from the world's biggest oil exporter expected steady supplies for December compared with November and most were still receiving much less than maximum levels.
"It's between 5 and 10 percent more," one source said, with reference to supplies to global firms for December compared with November.
"But we're still nowhere near the level at which we were."

So far OPEC is producing within the constraints that keep market price stable, with varying degrees of compliance to the overall target. However global demand can be anticipated to continue to grow as the effect on demand from the recession fade. China, for example, has just signaled its intent to buy around 1 mbd from Saudi Arabia next year.

The question will then come, as the available spare capacity in OPEC starts to diminish, how quickly will this impact overall price levels. One can envisage there being enough oil still in the pot that supply can meet demand through next year, but prices may rise a little in that time frame.

What happens beyond that? Well that’s where it gets interesting, and the reports that Western estimates of reserves may have been overinflated due to political pressure don’t help build confidence that all we will need to do is tighten our belts a little. And unfortunately that realization may arrive just in time for the next Presidential election.

However the IEA World Energy Outlook (WEO) is due out tomorrow, and it will be interesting to see what the actual predictions are that the IEA (a recently more cautious Agency than the EIA) are actually producing. There have already been stories, which I commented on last week that the IEA were cutting their projections of demand. The question then arises as to how they will address the potential of OPEC to meet even that limited demand.

Oh, and one last thing, I just got around to checking on what was happening with the Arthur Berman situation, and I may be one of the last to find out that the World Oil Editor was fired over the same situation. Boy! Somebody must have trod on some sensitive corns.

Horizontal wells and Gas Shales

This post is one in a series, describing some of the ways in which fossil fuels are produced, and in the current part of the series (listed on the right hand side of the site – you should start at the bottom and work up) we are focusing a little more on the procedures that are being used to recover natural gas from formations such as the Barnett, Fayetteville, Marcellus, Haynesville and Woodford shales. In this particular post I am going to concentrate more on the benefits of horizontal drilling through these shale reservoirs, rather than using the more conventional vertical wells that were used historically. This, and the next three posts in the series are likely to be a bit more technically dense than earlier posts but I am trying to illustrate some of the problems of production, and some of the gains that technology is bringing to help solve some of them. And while the reason for the horizontal wells can be simplified in this graph from Chris McGill, there are a lot of other things that have to be considered in deciding whether or not the horizontal well is going to be worth developing.


Comparative production from a vertical and horizontal natural gas well (Chris McGill). Notice the gain in production, but much shorter life of the horizontal well.

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. I am also going to repeat some information from earlier posts, since some of you may not have read them.


As we go deeper into the earth, the weight of the ground above us will also increase. For a very simple measure (and to make the illustrations easier to follow) 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 it 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 may not have to resist pressures of more than 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. if there was no pressure within the well). 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 by choking the flow out of the well when, after completing the hole, you go back to start production.

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 an 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 he equivalent of 4 miles horizontally through the oil-bearing rock, then the production per day may go up to 10,000 barrels. It is not always that easy to find reservoir data from two adjacent wells, one vertical and one horizontal but I found a paper on Natural Gas by Chris McGill, in 2006 from which I took the following graph. (or those who want to see what projections on NG were just those few short years ago – the paper is worth a cautionary read).

Comparative production from a vertical and horizontal natural gas well (Chris McGill).

It is interesting to note (vide the recent controversy over Arthur Berman’s opinions on horizontal well life stability of production), that the Horizontal well here had an operational lifetime of only a year, as opposed to the ten years of the conventional well.

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 they were 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.

Simplified picture showing two joint sets (the grid) as they could be intersected by a vertical and a horizontal well.

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 it may not be in the 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.

The article illustrates that concept with a representation of the horizontal well drilled perpendicular to the joints at an outcrop.

Representation of a horizontal well drilled in the Marcellus, shown against the natural fracture pattern (Source AAPG )

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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The costs and estimates of production came from the time that the original post on this topic was written, and costs (as you may have noted from the comments and from other references I have made) can now get as high as $8 million for a horizontal well. But I will come back and write more about penetrations and hydraulic fracture in the next post.

A grudging admission of error, but the world remains unaware

Very gradually the underpinnings to the “hysterical” side of the Global Warming debate are being eroded. I mentioned at the time, that Secretary of Energy Chu still waves the Mann “hockey stick” curve as a justification for spending more time worrying about future global warming, than the shorter term shortages of petroleum products for the United States consumer. There have been a number of revelations that have cast increasing doubt on that particular curve, favored though it is of politicians.

There have been increasing questions on the data that went into generating the “blade” of the hockey stick, which I discussed in an earlier post after it was revealed that the paper that Keith Briffa wrote that led to the generation of the blade, relied on a very small range of trees, including only one that showed the dramatic uptick of the hockey stick. Briffa recently commented

we noted that the final years of the Yamal ring-width chronology (Briffa, 2000; Briffa et al., 2008) should be used cautiously on the basis that the values for the most recent part of this chronology are based on relatively few individual measurement series and this smaller available sample emphasises the faster growing trees.

Given the subsequent history of the use of that data (vide the movie An Inconvenient Truth inter alia) it can hardly be said that those words of caution were heeded, or even recognized.

Questions on the validity of using that particular data continue, and correlations are now being made with actual local temperature measurements in the same regions as the tree data came from. What emerges from that correlation is

“Warmist” tree ring proxy temperature evidence is falsified directly by local thermometer records.

The data analysis is somewhat intense but well worth working through to understand exactly why that statement is justified.

And there has just been a new paper on this subject published by Devi et al. which argues for the consideration of ecotone movement in the analysis of the tree ring data, and shows that there was a change in the way in which the trees grow, a change which correlates with temperature, that can be traced back to early in the 20th century. (Thanks bender). But it blows another leg out from under the support of the shape of the hockey stick at the more immediate end of the line.

Meanwhile, if one travels back to the other end of the line, and the estimation of what the temperatures were like in the Medieval Warming Period, one has to remember that, prior to publication of the Hockey Stick, curve the IPCC did recognize the existence of those warmer temperatures.

Medieval Warming Period (IPCC 1996) and the curve generated from borehole temperature proxies by Huang and Pollack in 1997.

The difference between the IPCC curve, and that proposed by Mann was highlighted in a review of the borehole data, and can be seen in this curve:

Comparison of Mann’s plot (blue) with that of the earlier IPCC prediction (red), and the plot from Moberg (black). (Source )

Now it turns out that there were some significant questions about the data upon which Dr Mann generated those predictions of Medieval temperature. There exist a large number of scientific papers (which I have referred to in earlier posts) that show that the period did exist. (The very first paper that I looked at when I got curious about this subject showed its existence in the Sargasso Sea, for example). However the curve was itself underpinned among others by data from tree ring cores taken from bristlecone pine trees in the Western United States.

Bristlecone pine tree allowing historic temperature data acquisition.

The validity of using those tree rings has been questioned by experts in forestry and other contemporary evaluations have shown the Medieval warming period that Mann’s graphs did not.

However the curve was also based on other proxy data (i.e. other physical phenomena changes that can be correlated with temperature change). It is interesting to note that Dr Mann is now changing the basis on which his curve was produced though all the while arguing that the basic shape remains unchanged.

Mann’s latest plot of historic global temperatures.

Now given that this does not show any decline in temperature between 1940 and 1970, something clearly shown in the record, the accuracy of this plot, as with earlier ones, is up for grabs, but seems to indicate that the consistent valid criticism leveled at the paper by Steve McIntyre has yet to be completely addressed.

The controversy has moved on to the use of lakebed sediments from Lake Korttajarvi in Finland, which were cored by Mia Tiljander as part of a doctoral dissertation (hence the name Tiljander sediments). Analysis of the use of the data by others has recently led Kaufman to admit he made a mistake in the use of the data while reasserting that the correction merely strengthens his original argument.

That a correction that re-inverts the data strengthens a correlation seems to be odd to me, but then this whole basic argument over the data and its interpretation has been redolent with somewhat dishonest and manipulative practices on behalf of those generating the information that is used by the IPCC and our Secretary of Energy.

When one realizes that much of this manipulation comes from folk that work in the government and are supposed to be disinterested in the results it becomes more irritating. But then one must recognize that their funding and jobs do, to a significant extent, depend on Global Warming being real and man-made.

I would recommend reading the review of all this at the Skeptical Climate Science Primer since this story is told there with many more graphs and details than I can put in the posts that I produce.

Availability and Profitability of Natural Gas and LNG

It is a little difficult to predict, just at the moment, which way the natural gas situation is going to swing over the next year. The number of different events that are contributing to the overall supply of natural gas seem, on the surface, to indicate that there will be more natural gas than is needed. But there is some question as to how much will actually appear, as the year develops.

For those who want everyone to believe that there is no longer a shortage of natural gas there are the additional LNG supplies that are now coming on stream. Just this week Yemen begins shipping its first cargo to Korea, with a second cargo from Belhaf soon to follow. The gas comes from a reservoir in the center of the country and had to travel some 320 km to the processing plant and terminal. The first train is committed to the Korean market. A second train is expected to be brought on line in a few months, to raise total production to some 6.7 million tons per year. While the market for this second stream was originally expected to be in the US, at present they are keeping it closer to home by intending to sell to India.

The USA had been seen as a sure market for LNG at the time that Belhaf was planned but that was before shale gas began to hit the scene. Now, the declining price in the American market, and the prevailing large quantities in storage, make that less desirable.

Moving around the coast to Qatar, business is good with three LNG vessels shuttling to the UK this month. With three LNG terminals – at Dragon, South Hook and Isle of Grain, the UK can now import up to 25% of its needs as LNG. That is helping to keep the price of natural gas lower in Western Europe and has a natural knock on to prices that those countries want to pay to such companies as Gazprom.


Qatar is simultaneously setting up to be a major supplier to China. The Chinese see that market being in the range of 40 to 60 million tons by 2020. They have just started taking delivery of an initial 2 million tons per year from Qatar.

Back in early 2006 when the expansion of LNG trains was planned for Qatar it was expected that the US would be buying up to 30% of its needs from Qatar and Qatargas Trains 3 and 4 each with a capacity of 7.8 million tons, were started on that assumption. Now, of course, with the increased domestic production from the shales there is no longer such a need and the question becomes one of working out where the new surplus of natural gas will go.

Part of this may go to Europe to replace the Turkmen gas that may not make its way West this year, since Turkmenistan and Russia (not to mention Russia and Ukraine) still seem to be at odds over the price and profit that they each might make from supplying gas West. Turkmenistan can now hold on, given that it is selling its natural gas to China, in almost the same quantities, but for a much better price. Russia is, however, starting to get natural gas from the new Achimov deposit. The declining market, due to the recession, has seen Gazprom sales fall, but they are now claiming some turn around in that situation. incidentally, those who wish to get some idea of why it might be hard to gain a good idea on Turkmen reserves and production should read Shaun Walkers story in The Independent.

Not that China is content to just rely on the new feed from Turkmenistan. It is also starting to import LNG from Malaysia through a new terminal at Shanghai, and will purchase the LNG from Qatar train 2. A third Chinese LNG terminal also began operation earlier this year.

Now that is all the good news about supply. The questions that remain relate to the production that can be anticipated from the gas shales in the United States. The problems of maintaining production from gas fields that can drop production by over 20% in a month, or 80% in a year are not yet recognized. One significant one, that Arthur Berman raised as a concern, is the ability of wells to attract enough investors to pay for sinking them. If the recovery rate from the wells requires a high price and sustained volume to attract those investors, then the availability of cheaper LNG from the Middle East may keep the price from reaching the levels that are needed. Another LNG terminal has just been approved for Port Dolphin in Florida, while there is growing support for a facility at Coos Bay in Oregon. But that is, in the short term, seeming to bring in natural gas into a country that already has enough. The EIA notes that the current price of natural gas (Henry Hub) is around $4.289/kcf - the threat of imports from abroad will likely keep it down at around that level this winter. The question then comes as to whether, at that price there is enough profit in the gas wells to continue drilling in the gas shales.

I suspect that the hype, for a short time, will keep that program running, but if you’re losing money on production you can’t make it up on volume. The rig count is slowly rising, but whether the resulting production will make money, and how long will the wells last are topics for another day. Though cold weather, short term, might help in reducing what continue to be record stocks of natural gas.

Future Projections of Oil Demand and the IEA WEO

Exasperated sigh! Well there is this story in the Wall Street Journal that has also been picked up over at the Financial Times that deals with a “leak” of the predictions that will come out of the International Energy Agency next week, with their new World Energy Outlook. (Thanks, Leanan) The story begins:

The International Energy Agency next week will make a "substantial" downward revision to its long-term forecast for global oil demand, a person familiar with the matter said, marking the second year running the group has slashed its view of the world's thirst for oil.

Now this is where we start to get a little argumentative. Not because the amount of oil will actually reach 106 mbd as the WEO suggested last year, but rather because of the reasons for the actual number likely not being that high. (And there is a caveat to this – shades of Daniel Yergin – in that I am talking about fossil fuel and not what might, by then, be available from biofuels, since in that time frame algae may be a practical source of significant volume.) Every month I write a post on what is happening with the nations driving habits, and tie it into gasoline demand. The last curve shows that, even though we are have been in an economic slowdown for over a year that the nation’s driving level has already returned (on a 12-month cumulative value) to the point it was in 2004.

2 month running total of vehicle miles driven in the USA. (FHWA)

Given that a majority of the crude oil produced goes into transportation fuels, and that those demands are likely to see an increase, other conditions being equal, from the increased market for cars in Asia, initially demand will not reduce because of conservation.

Ford just announced that Chinese sales in October were 20,027 cars, up 80% over a year ago. For the year so far they have sold 188,244 cars up 40% on the same period last year. Increasingly new car volumes are being driven by sales in the emerging markets of Asia Suzuki profits are four-times higher than anticipated because of sales in India. They sold 85,415 units there in October, and a growth rate of 20%. Overall sales for the year are expected to be around 1.8 million vehicles. Part of the sales have been driven by the Indian equivalent of “Cash for Clunkers” but it is also moved by the desire for vehicles and the ability of manufacturers to now start to provide them.

Tata Motors reported a 28% increase at 22,232 units, the highest this fiscal. Ford India and General Motors India also showed significant growth in October 2009. Ford saw a 98% jump in sales at 3,458 units, primarily triggered by growth in Fiesta sales. Riding high on the success of the Chevrolet brand, General Motors India registered a record growth of 15% in sales at 7,413 units in October 2009.

The size of the demand, therefore, could have been expected, were there copious amounts of fuel to be available, or even just adequate amounts at a reasonable price, to may well have continued to increase to the level that the WEO will predict. The problem will come, not from that part of the equation, but rather from the supply side. And here, I would suspect, since I haven’t seen the report yet, that the WEO will continue to obfusticate around the issue.

To reiterate, we know that non-OPEC global production has now fairly evidently peaked and is in decline. OPEC retain the capability to increase production by perhaps 2-3 mbd, at best, and face, well within the period to 2030, the likelihood of dropping production from their major fields. The number of countries that can produce at 1 mbd now just about fits on a single slide for one of my lectures:

World’s largest Oil producers (production in parentheses is from 2004, and red highlights shows those declining in production).

I see that at the end of the article Daniel (Yergin) is finally admitting that there is a peak production coming in the future

There is a market assumption today that we will head back to the old days of rapid oil demand, but we think we are heading into new days," in which the growth in consumption will be more subdued, said Dan Yergin, chairman of IHS Cambridge Energy Research Associates.

Hard to back away from those cornucopian dreams, isn’t it, Daniel?

No, the sad fact is that the limited availability of crude is going to drive up the prices within a couple of years, so that it will be this that limits and changes demand, rather than the impacts of those driven by the desire to guard against Climate Change by moving toward a more energy efficient future. Not that energy efficiency has anything wrong with it, just that the incentive for change is going to come from an unavailability of oil at a reasonable price – so that both price and production limits will constrain use in the 2030, to levels well below those of today, rather than higher, and we need to be working on alternative replacement strategies a lot harder than we currently are. The IEA WEO will not, unfortunately, provide much ammunition for that argument, as it would appear.

Arthur Berman leaves World Oil magazine

This is just a short note, since Tuesday's tend to be my busiest days in class, but I could not help but put up the news best reported by quoting from Arthur Berman's Petroleum Truth Report

In an act of extraordinary courage, a top Petrohawk executive threatened to cancel his free subscription to World Oil if the magazine continued to publish my column. Today, John Royall, President and CEO for Gulf Publishing, cancelled my November column.

I have accordingly resigned as contributing editor.

For those of you who do not understand the import of this, Arthur Berman has been writing for some time about the credibility of long-term natural gas well production claims from the gas shales around the United States.

There has been a considerable hype about these shales (hence the tech series that I am starting to post on Sundays) and the wealth of natural gas that they are adding to the nations reserves. However, through examination of some of the records Arthur has shown that the performance of individual wells is not holding up to the original promise.

For example the industry relies on a decline model for well production that, over time, allows one to make a certain prediction for the recovery of natural gas from that well. Thus, for the sake of example, integrating over time the amount of gas might suggest that a field might ultimately yield 2.5 billion cubic feet of natural gas.

However, by examining records that show that the declines rates are much faster than predicted (see my post on his paper at ASPO) he has shown that the reserve from these wells might come in at only half, or less, that predicted.

Given that the wells are extremely expensive (at around $8 million or so) Arthur calculates that the industry needs a price of $9 /kcf to make a profit on a well with about 2.5 bcf in reserve. What he is seeing is that with the more rapid decline rates that are being experienced in the Barnett and Haynesville, and the current drop in natural gas prices, that neither of these conditions is being fulfilled. Thus he is strongly questioning the financial underpinning to the health of those that are heavily engaged in these gas plays.

Of these, Chesapeake and Petrohawk are the largest, though I have largely confined most of my posts to Chesapeake, since it was their testimony before Congress that suggested that they could operate with a price of $4/kcf. Obviously Petrohawk feels threatened by his commentary, and has acted accordingly. It is disturbing that World Oil seems to have folded so easily to that pressure.

Shales and the gas within them

This is Sunday, so this is a technical talk about getting fossil fuel out of the ground. While some previous posts have dealt with sandstone and carbonate deposits I’m going to be talking about getting gas out of shale for a couple of weeks, and so, before I started talking about Horizontal Wells, we’d better chat for a minute or so about shale. And when I don’t give an alternate reference for the information, I am likely quoting from the Primer on Natural Gas in Shale, from the Department of Energy.

Folk who live near rivers, or along their outlet to the sea are familiar with the large mud flats that can develop around the outlet. These flats, which extend out into the sea, can cover large areas. When I was in school at Lancaster in the UK, we went to Morecambe Bay when my parents came to visit, and the large areas exposed when the tide ebbed remain a lasting memory. Through geological time these beds of mud have lain under large stretches of water, and so, at the algae that float in the water died, so they fell, and were caught in the mud. The mud is largely made up of clays, which in very small sizes are shaped a bit like a plate, and so as they settle, capturing and covering the algae remains, they tend to create layers (which can later tell us some of the conditions at the time they were deposited). When conditions are right – generally with a relatively warm sea containing a lot of nutrients – the sea can host vast colonies of algae, and over geological time the death of these algae built up considerable organic matter in the mud on the sea bed.

The main gas shale deposits in North America are in the Barnett shale, the Fayetteville, the Woodford, the Haynesville, and the Marcellus while, in Canada, the large fields are in the Horn River and Montney deposits. Not that there are not others, but these are the ones that the Oil and Gas Journal calls “The Magnificent Seven.” As an example the Barnett shale was deposited during the Mississippian Epoch, itself part of the Carboniferous Era, between 315 and 350 million years ago. At that time the map of the Earth looked at bit like this ) .

Shape of the Land and Seas at the time of the Mississippean Epoch

However not all the shales were deposited at that time. The Haynesville, for example is much younger, having been laid down in Jurassic Era, (remember the dinosaurs of Jurassic Park?) which was some140 to 200 million years or so ago, and when the globe looked a bit more familiar.

The map of the earth some 195 million years ago during the Jurassic

The mud that was deposited grew to be very thick – even after it was compressed by the weight of overlying additional sediments that turned into rock, the Barnett shale still can measure between 50 and 600 ft thick.

The individual particles that made up the mud were quite small, so that, as the material was compressed, the resulting rock became relatively impervious. Thus if the gas-generating algal remains were trapped, they were held in the shale, but dispersed throughout it, rather than concentrated in larger pore spaces, such as are found in sandstones. And, to be economic, there still needs to be a significant amount trapped within the pore space, which needs to be at least in the 5 – 12% range to hold enough gas to be worthwhile. Putting this into a different context, the Barnett, for example, is estimated to hold about 325 scf (cubic feet at a standard defined temperature and atmospheric pressure) of natural gas per ton of rock – or in about 13 cubic feet of rock. (Needless to say deep in the ground the gas is very compressed).

As the rock was buried deeper, so the temperature and the pressure also rose, gradually “cooking” the organic material over time. Depending on how deep the rock was buried, and the temperature, the material either turned into an oil, or if it were buried deeper and at a hotter temperature, it would turn into a gas. The relative conditions that set these bounds are sometimes referred to as the oil and gas windows for rock, and can be illustrated with a graph.

Geothermal gradients defining the oil and gas windows as a function of depth and temperature. (From WVU)

The current reservoir depths at which the different shales are now found can differ quite significantly from those at which the gas or oil was first formed, with depths for the Fayetteville being as little as 3,000 ft (0.9 km) to the Haynesville which can be at more than 14,000 ft. (4.3 km). The Barnett is around 6 - 8,000 ft (2.4 km).

Permeability, or the ease with which gas, oil or water can flow through a rock is measured in a unit called a Darcy, but it is sufficiently large that most rock permeabilities are measured in thousandths of a Darcy, or millidarcies (Md). As a point of reference for a rock with a good permeability such as the Ghawar oilfield in Saudi Arabia, Greg Croft quotes values in the 600 Md range.

A microdarcy is one thousandth of the value of a millidarcy, and it is this unit that the permeability of gas shales are often measured. Thus the permeability of the Marcellus shale can be around 20 microdarcy and the Barnett around 10 microdarcy. The density of the rock can be seen from the sample pieces shown at the Chesapeake Web site.

Illustration of gas shales from the Chesapeake web site.

These fine-grained rocks with low permeabilities mean that the producer has to rely on other paths within the rock to allow the gas to escape. Originally this was just the natural fractures that can be found in the rock. As the rock compresses vertical fractures often generate within the rock. These fractures can be quite consistent, though in contrast to the bedding, they normally occur vertically.

Shale fractures from Geology.com

The problem is that conventional vertical wells don’t intersect a lot of these fractures, and thus, when the gas shales were first drilled the production was very low, and often uneconomic.

However when horizontal wells were developed it became easier to intersect a lot of these fractures as the well moved along the reservoir, and so it is time to introduce horizontal wells in the next post.

As usual this has been a very short description of a relatively complex topic, and so questions, and comments are appreciated.