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

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

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

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

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

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

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

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

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

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

And in this regard, the rising costs of wells, against the more difficult to assure profits is beginning to have an impact on the willingness of companies in the United States to invest the large quantities of capital into new wells that is needed to sustain and grow production. A recent article in Rigzone took note that the major oil companies are rethinking their strategies of investment, with some reorganization of their plans in particular for investment in shale fields. This raises a question for the author:

Another question for the industry is who will supply the risk capital for exploratory drilling, both on and offshore, if the majors pull back their spending? Onshore, for the past few years, a chunk of that capital has been supplied by private equity investors who have supported exploration and production teams in start-up ventures. They have also provided additional capital to existing companies allowing them to purchase acreage or companies to improve their prospect inventory. Unfortunately, the results of the shale revolution have been disappointing, leading to significant asset impairment charges and negative cash flows as the spending to drill new wells in order to gain and hold leases has exceeded production revenues, given the drop in domestic natural gas prices. Will that capital continue to be available, or will it, too, begin demanding profits rather than reserve additions and production growth?

Before investors put up the money for new LNG plants they need to be assured that there will be a financial return for that investment. Given that it takes time for such a market to evolve, and given the need that Russia has to sustain its market and potentially to increase it, the volumes that the US might put into play are likely to be small, with little other than political impact likely.

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

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

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.

An interesting, and worrying talk at ASPO

Unfortunately I have had to miss the ASPO Meeting in Denver this week, and so cannot provide the daily reports that I have written in the past. But I notice that at least one of the talks has already caught a significant amount of press, and that is the one by Arthur Berman on the gas production from shale deposits such as the Barnett, Haynesville and Marcellus.

There has been a considerable hype in the press about the value of the gas from these shales, and the ability that they provide to bring in an “Age of Natural Gas”. Commenting on the situation last year, the CEO of Chesapeake noted

"the U.S. today consumes about 63 billion cubic feet of natural gas per day - in energy BTU equivalency terms, that’s 10.5 million barrels of oil per day, or about half of the amount of oil that the U.S. consumes each day. Of that 63 bcf per day of natural gas consumption, we import about 1 bcf in the form of liquefied natural gas, or LNG, and we import about 8 bcf per day from Canada. This means that we are about 98.5% self-reliant on natural gas supply from North America and about 86% self-reliant on natural gas supply from the U.S. Contrast that with oil, where we are only about 41% North American self-reliant and only about 27% self-reliant from U.S. sources."

This picture of a large supply of natural gas has been strengthened by the increase in production from a number of the gas shale fields, at the same time that the recession hit, and as a result there has been more gas available than needed, and the price has dropped considerably as a result. This, in turn, has led to a considerable reduction in the number of rigs that have been drilling new wells.

Natural gas has been steadily increasing its share of electricity generation, rising to over 20% of the market, on its way to 25%. Natural gas is favored because of its reduced carbon footprint over coal, and it has historically been used since it is somewhat easier to start and stop gas turbines than it is coal-fired power. Thus natural gas is seen as a favored backup to the installation of wind farms, where the vagaries of the wind are backed by the ability to use natural gas when needed.

There are, however, considerable concerns about the ability of wells in the gas shale to produce to the targets that are being set up. I first noted Arthur Berman’s concern about this back in 2007 when I drew attention to a piece he had written in World Oil, where he noted the short life of most of the gas-producing wells; the very high costs for the wells and technology required to create them and, as a result, that only 28% of them return a reasonable profit. (Unfortunately the article itself is now behind a paywall).

Since then I returned to the topic at Bit Tooth showing, among other data, the very high decline rate (now 60%) of many of the gas wells in Texas (where the Barnett shale is) that Swindell has reported.

First year decline rates of Texas natural gas wells (after Swindell)

There is further disquieting news that is now coming out of the Barnett field. The Ft Worth Weekly has just reported that many of those who expected to make substantial amounts of bonus money from drilling companies using their leases have had the agreements withdrawn and lost their money.

In April 2008, the Southeast Arlington Communities of Texas (SEACTX) negotiated a deal with XTO Energy that would bring in bonus money of $26,517 per acre and a royalty rate of 26.5 percent - among the highest in the Barnett Shale play. When leaders of SEACTX, representing about 7,000 property owners with about 5,000 acres, did the math, they figured that more than $100 million in upfront bonuses would be coming into their community of mostly modest to middle-class neighborhoods. . . . . . . . . . Well, that was then and this is now, when natural gas prices have fallen to less than half what they were in early 2008. And as anyone who has been following the Barnett Shale saga knows, drilling companies pulled out of those deals and others in mid-October of last year. Some property owners, whose bonus checks were processed prior to the cancellation, got paid. Tolli Thomas, a spokeswoman for SWFA, estimated that 4,000 to 5,000 people in her area got the money promised to them - and the other 20,000 or so did not.

Prices for drilling these wells run on the order of $5 million apiece, and Chesapeake has, in the past, noted that it takes $4.00/kcf to bring in enough money to cover those costs – with a good well. (Note that this is the Henry Hub price, consumers should add about $3 to this to get the residential price). Those numbers are considerably higher than the ones that Mr Berman used with his calculation two years ago that only 28% of the wells will be financially remunerative.

He recently (April 2009) expressed similar concerns about the Haynesville wells – though his production decline numbers are stunningly higher – as much as 20-30% in a month, for an annual decline rate of 80-90%. The costs that he cites are up at the $7.5 to $9.5 million range for the wells, with a net final cost that the producer has to pay in the region of $7.25/kcf. He therefore concludes that the breakeven point for wells in the Haynesville lies at a price of around $9/kcf Henry Hub; with a minimum reserve of some 2.5 Bcf. He upgraded that opinion in June expressing a concern, that I echo, with the availability of natural gas from a variety of sources (including the Rocky Mountain Express and increased LNG shipments) which will make it difficult to sell gas from formations such as the Haynesville, at a profit.

In his most recent post on the subject some of the possible reasons for the rapid decline (which fall a little along the same explanation as I gave on chalk collapse) which are as follows:

An abnormally high-pressure gradient (0.7-0.9 psi/ft) distinguishes the Haynesville from other shale plays. It may also explain the extremely high decline rates, as pressure depletion transfers stress to the rock and allows proppant-filled and open fractures to compress, thereby reducing the effective reservoir permeability.

Unfortunately for the hopes of a new age for gas, in preparation for a meeting on the Haynesville production last week, he had calculated the numbers for some 67 wells in the Haynesville and was still coming up with decline rates of 25% a month.

He also noted

The average EUR in our study is 1.72 Bcf/well, compared to the 6.5-7.5 Bcf/well reported by many operators. Only two wells of the 67 evaluated have an EUR greater than 6.0 Bcf. At the same time, seven wells have already produced more than 2 Bcf and one has exceeded 4 Bcf.

Petrohawk has the best well performance with an average EUR of 3.4 Bcf/ well (19 wells evaluated). Chesapeake has the most wells on production (29 wells evaluated) but we project an average EUR of only 1.2 Bcf/well.

It sounds as though I missed a really interesting and valuable talk – just have to wait for the DVD’s to come out, I guess!! But in the meantime I have added his site to my recommended reading list, over on the right.

I'm also going to have to reorder some of the technical talks on Sundays so that I can more fully explain his concern about the Haynesville shale.

P57. Pick Points

Over at The Oil Drum, Jon Friese has a guest post with an interesting plot of the relative drilling activity in the four major gas shale fields. It shows that while drilling in the Fayetteville and Woodford shale has remained relatively stable, there has been considerably more activity in the Haynesville shale, and a rapid drop-off in rig count in the Barnett. Overall the number of rigs drilling in gas shale has held remarkably constant over recent months at around 230 rigs, though this is down from the peak of 311 rigs last December. This is happening just as a new pipeline extension is connecting into the Barnett field. The Sherman extension to the Enterprise Texas Intrastate connector will carry up to 1 bcf out to markets as far apart as the North East and Florida. The Barnett had increased production in 2008 to nearly 1.4 tcf, and had 10,500 wells with 222 companies operating. But over the last few months the rig count had fallen 57% from 214 rigs to 91. With an average of 25 people per rig this is a loss of some 3,000 jobs. Meanwhile Exxon Mobil has leases on 19,400 acres in the Marcellus shale.


Oh, and in the great game of Azerbaijani natural gas, the Russians are now trying to get the gas that might go West to Turkey, to go instead North to Russia (who could then sell it into Europe). It is part of the ongoing struggle over supplies for the Nabucco pipeline. Gazprom is also trying to raise $500 million on the Eurobond market. Further East, the pipeline from Turkmenistan to China should have the Turkmen leg finished this year. Gas should reach peak flow (30 bcm per year) in 2011. And the Turkmen are still talking about possibly piping natural gas down to India and Pakistan. It is needed since even exports of goods from Pakistan are now being reduced due to shortages of natural gas. India, meanwhile is bringing new gas on stream and using natural gas increases from current fields to improve fertilizer production.

While Mt Redoubt is relatively quiet today, there are signs of new eruptions from a volcano in the Congo that last erupted in 2002, nearly destroying the nearby town of Goma.

Financing for wind power in the UK appears to be rapidly fading

Despite the fact that the UK has richer ambient energy resources than any other country in Europe, the government managed to beat its target for renewable power down to 15% of total energy supply, rather than the 20% adopted across the EU. Even so, this means that by 2020 35% of our electricity must be produced by wind, hydro, wave, tidal, solar or biomass generators. The technology that could be most widely deployed is wind power, but investment is melting away faster than an Andean glacier.

Shell has pulled out completely. Centrica, E.ON and BT are reviewing their plans. Sun Microsystems has suspended its projects. The Spanish company Iberdrola is cutting its investment in the UK by 40%. Scores of smaller firms are going bust.

On the other hand the British government has just offered increased financial support in order to get production closer to target.

The government is also planning to sign contracts with companies by the end of the year to develop up to 25 gigawatts of offshore wind power that will be awarded from its Round 3 development phase.

But developers are anxious about financing the investments, which, at about GBP3 million a megawatt, are roughly double that of onshore wind.

The recent banking crisis has also made project finance difficult to come by and more expensive.