P30 Pick Points

Half-a-dozen or so stories of interest:

Moving to undo some of the last actions of the Bush Administration Interior Secretary Salazar has cancelled the lease agreements that had earlier been approved (but then delayed when the government did not cash the checks) in Utah for oil and natural gas. At the same time, in Wyoming some sales are proceeding, while other leases have been withdrawn at the Governor’s request.

Adding additional numbers to the costs for drilling wells in the gas shales, Encore Acquisition have stated that their goal this year, in the Bakken, is to reduce costs from $5 million per well to $4 million. They are also planning refracs of some of the wells. These are done some 9 – 18 months after initial completion, and at a cost of $500,000 each can increase reserves by up to 80,000 boe. Over in the Woodford, Newfield Exploration have lowered (on a lateral foot basis) the cost of drilling wells by some 38% and are hoping to continue this trend by drilling longer wells (out to 5,000 ft from 4,436 ft last year and 2,700 ft in 2007.) Lease rates in the Marcellus were reported to be up to $4,000 an acre and 17.5% royalty, prior to the slackening of demand.

Public relations in the Barnett still appear to be becoming more difficult, as an application for a compressor station has just been withdrawn. Without the dramatic reductions in well costs, and without an increase in gas prices unlikely in the present glut of gas, the current economics of many operations are being further questioned by Arthur Berman.

Royal Dutch Shell said that the cost of producing oil from the oil sands of Alberta rose to $38 a barrel last year. Their production dropped last year to 80,000 bd falling 7,000 bd from 2007, while costs rose by $9 a barrel. More than $60 billion worth of projects have now been delayed, including the expansion of the Shell output to 250,000 bd, which was scheduled for next year. Meanwhile Marathon has written down the $1.4 billion cost of its oil sand operation. Canadian Oil Sands trust, the largest shareholder in Syncrude Canada cut its dividend 80% because of the drop in oil prices. Meanwhile BP and Husky have not yet gone forward with their investment on the Sunrise assets in Alberta. Yet the prospects are such that a firm that specializes in the construction side of the development has just been taken over by Aecon. They, however, do not have to deal with the stronger environmental rules that are now being applied to the tailings ponds.

Merrill Lynch says non-OPEC oil production has peaked, expecting that such production will be in the 49-50 mbd range by next year, while the IEA were predicting last summer that the peak would be next year at around 51 mbd. The Merrill Lynch projection is based on an increase in field decline rates which they set at 4.5% against the IEA figure of 4.2%. The IEA recognizes that the decline rate will rise to 4.7% in the next seven years, but this will slow, not stop increases in production. In contrast ML argue that some of the decline will come from the loss in capital availability and this will carry decline above 5% (and perhaps as high as 6%). Should this happen then within a year oil prices will be back where they were earlier last year. A year ago CERA were saying that a 4.5% rate was typical but they were saying this as rumors and reports of figures already above 5% were starting to circulate.

It looks as though Croatia is going to be the next meal for Gazprom as plans for the Pan European Pipeline start to collapse, and their experts head off to Moscow. With Nabucco also still not having enough gas commitment to be viable and Gazprom is making promises to Turkey about providing natural gas their dominance becomes more evident. With the upcoming North and South Stream deliveries giving Russia the chance to provide for 50% of Western European gas needs (up from the current 25%), the only question becomes where does Gazprom get all the money to fund these developments? It must find $10 billion in debt payments by the end of July, and just lost up to $2 billion in the dispute with Ukraine. As a result they are sweetening their stock offers, even as their production of natural gas falls 14% y-o-y . On the other hand, as deliveries through the Baku-Tblitsi-Ceyhan rise, those through the Baku-Novorossisk pipeline are falling.

Over at the European Tribune Luis has just finished his 3-part review of the plan to Secure the Energy Future of the EU, with earlier posts on the Action Plan and an Introduction. Given the outreaching hand of Gazprom, it is worth getting to know this background, before it gets more serious.

More stories can be found at The Energy Bulletin and Drumbeat at The Oil Drum

9. Why Europeans aren't the only ones who should worry about Natural Gas

The first of the Tech note posts dealt with the initial creation of coal, and so obviously I will be coming back to talk about that at some time in the near future. Most particularly I will be challenging some of the conclusions of Dave Rutledge, whose opinion on coal reserves has been publicized recently in WIRED. (Hat tip to Devin). However, some of that requires a bit of a foundation, which will continue to be built over the next few Sundays. Instead, what I want to begin to also develop are some posts about the natural gas situation in the United States (the situation in Europe is highlighted by the Russian:Ukrainian dispute).

The reason for some initial groundwork on this topic is that, at the present, the US has a surplus of natural gas, and this is driving the price down, even as demand rises. Sadly this is a relatively short-lived situation and going to start to have some significant unfortunate consequences probably within the next year to eighteen months. What I want to do is two different things – the first is to roughly identify the problem, as I see it, and then in some later posts to explain some of the technical problems that have led us to where we are today. Today’s post will, however just outline the problem, which begins with the current cost for a new gas well of around $5 million.

The reason that the country currently has a surplus of gas can be traced back to a couple of different causes, the development of a gas pipeline from Colorado to Ohio, and the more critical extraction of gas from the shale deposits around the country. These latter reserves were needed since, over time, the earlier supplies of natural gas from more traditional sources such as wells in the Gulf of Mexico and Texas have been declining. The problem is well illustrated by information that Gary Swindell has illustrated and from whose work I would like to take a couple of graphs. In Texas the overall production has been relatively stable at about 500,000 mmcfe a month for the past decade. However, in that time the average size of the wells that are being produced has declined.

Average size of wells being developed in Texas (from Swindell)

and the average decline rate, in the first year of production, has climbed to 60% of the initial production rate.


First year decline rate of Texas gas wells (from Swindell)

Notice that the decline rate reached this plateau in around 2000. This is when the first wells started being sunk into the Barnett Shale, which is a gas bearing rock that underlies Dallas and Fort Worth, among other places. It is currently being developed, and there are over 6,000 wells already drilled into the formation.

Now I will get into all the complexities of drilling and producing gas from the gas shales in a separate post on some future Sunday, but for now there are two things to note. The first is that with more than 60% of the wells initial production dropping off in the first year, new wells have to be drilled at an ever increasing rate (as the fields get smaller) in order to maintain production. Swindell notes that 18% of the production now has to come from new wells every year.

However drilling these wells is very expensive, as Comstock reported yesterday, these wells are now costing up to $5 million each. And the problem is that the relatively short life of the wells, and the levels of production that are achieved, are not giving an adequate rate of return.

Last year I noted (when the wells were costing $3 million), drawing from Arthur Berman’s analysis that only about a quarter of the wells were likely to be profitable. With the increased costs, this number, despite today’s rally in stock prices - driven by the Russian:Ukrainian debacle, when taken with the drop in natural gas market price means that there will be less incentive to drill new wells, and rig numbers will significantly fall.



Rig numbers are already falling rapidly. The concern is, that with the need for a continuing supply of new wells to sustain U.S. Natural Gas production, there will soon not be enough wells being drilled, or rigs drilling them, to meet the shortfall in supply as the current wells start to run dry within the year.

Oh, and Russia does not plan on exporting LNG to the United States.

And while I am talking about exports, there is useful information on fuel exports that can be found at the Energy Export Data Browser