Tech Talk - Where to look for more oil this year.

The news that Saudi Arabia is planning to employ 200 drilling rigs next year (up from 20 back in 2005) suggests that there is a recognition that future reserves may not measure up to the planned volumes needed. Plans now include exploration of the shale deposits in the country, looking primarily for natural gas. There are estimates that this resource could run as high as 600 trillion cubic ft. Current plans are to drill seven exploratory wells in the Red Sea, off Tabuk.

Figure 1. Location of Tabuk in the Kingdom of Saudi Arabia (WikiMedia )

This is across the country from the major oil fields currently in use, which lie more along the Persian Gulf coast, centered perhaps around Damman. It therefore suggests that they are looking for extensions of the Israeli and Egyptian fields into northern KSA. (Minister Al-Naimi said that they still “had to find them.”)

In discussing the venture Saudi Minister of Petroleum and Mineral Resources Ali Al-Naimi also noted that, choosing to look for – and presumably finding - natural gas, would take the pressure off the country to maintain its oil reserve.

Al-Naimi said that prospects for global production of shale gas and oil – including in China, Ukraine, Poland and Saudi Arabia – were so promising that the Kingdom might not need to continue with its decades-long policy of maintaining an oil-output cushion for use in global supply disruptions.
“It is not a question whether Saudi Arabia has spare (oil) capacity. It is a question of whether we need to spend billions maintaining it at all,” Al-Naimi said.

Now over the years KSA has lowered the volume it has projected that it can produce from 12.5 mbd to 12 mbd, and this is, perhaps, an early indication that they intend (whether by policy or natural reserve availability) to lower that maximum further.

This has to be of at least a little concern, since the number of places with significant flexibility to increase production are getting closer to zero every year. The gains in global production that are foreseen by OPEC in the next year, for example come in dribs and drabs.

OPEC notes that in May the 8,915 producing wells in North Dakota collectively produced over 800 kbd. (The Department of Mineral Resources reports 821 kbd in June, over the 811 kbd in May with well numbers of 8,932 in May and 9,071 in June. Production per well is thus running an average of 90 barrels a day, with a well cost of $9 million.) There are 187 rigs plus/minus working and this is still enough to keep production rising at a rate of 1.3% per month. One of the maps I find interesting is this, from the Department.

Figure 3. Location and production values for wells in North Dakota (Department of Mineral Resources )

It is this illustration of the relatively heavy drilling already in the “sweet spots” and the poorer performance in the less well drilled regions that gives me concern for the longer term prospects for the formations. And as an aside note that crude from Alaska is declining, July output was 498 kbd against the year-to-date average of 542 kbd. The EIA is noting that, since there aren’t any major oil pipelines running into California from the East, that there is an increase in rail traffic to make up the difference. The EIA is suggesting that the traffic is already at a level of around 100 kbd.

And this in happening in the most promising region to increase production (though it includes Canada, for which OPEC projects a growth over the year of around 40 kbd, which is set against Mexican production, for which OPEC sees a decline of around 60 kbd).

Malaysia is projected to increase production by 50 kbd, from the Gumusut field. This is a Deepwater project, and one can get some estimate of the shape of the field from the well pattern. The production gain is viewed by OPEC as likely being the highest in the region.

Figure 4. Planned Well pattern for the GUMUSUT KAKAP project in Malaysia (Rawingbadi)

In Latin America Colombia is expected to increase production by 80 kbd, though the country is having some issues with pipe damage from terrorism. There have been more than 30 attacks this year. OPEC also looks for an increase in Brazilian production of 10 kbd over the year, this gain coming after some 14 months of decline, which drop hopefully will be recovered before the end of the year.

Oman will grow production by 20 kbd, but it is in Sudan and Southern Sudan that OPEC anticipates the greatest growth, of 90 kbd. However the two countries are not the best of friends, with oil from Southern Sudan having to ship by pipeline to Sudan, for shipment onwards. At present oil, at an average rate of 75 kbd is continuing to flow up the pipe, but Sudan continues to threaten to halt shipments, leading Southern Sudan, in turn, to plan to shut-in the wells. The OPEC projection seems to be best defined therefore as “iffy.”

OPEC expect Russia to increase production by 80 kbd in 2013, yet there is some caution in that estimate, with other numbers suggesting that Russia is reaching a modern peak in production. Kazakhstan is projected to increase production by 50 kbd (coming from the startup of Kashagan, now expected at the end of September). The 100 kbd production will more than offset declines in the rest of the country. And China may increase production over the year by 60 kbd.

I have listed the countries that OPEC anticipates will grow production by more than 10 kbd, and have not listed the many countries that will see production decline by more than that amount. It is remarkable that listing the increases in production outside of OPEC can be done with just a few paragraphs. And it is a little disturbing that the threats to pipeline security throw questions over the reliability of some of the numbers. And yet this only addresses the possible growth in production, declining producers would require a much longer list. Combined it becomes a little more difficult, as turmoil in MENA continues to grow, to remain optimistic over the OPEC projections.

Native American features and history - an introduction

This post originated when I began to model Indians in Poser (a 3-D computer modeling program) for my own amusement and as a way of learning how better to use that program. (Indians at around the time they first met with Europeans and through early Colonial days did not wear much in the way of clothing, making the models easier to make.) But the obvious initial question was “who did they look like?” My curiosity was driven from an early illustration my Dad had sent me of an Indian miner on the shores of Lake Superior in the early 19th Century. I imagine that he was mining for copper, (native in the region) and I was struck by his appearing quite European.
 
Figure 1. Sketch of a 19th Century Native American miner on the shores of Lake Superior.
 This is also how Robert Griffing (a currently popular painter of early Indian encounters) has been painting them. Given that this seemed to conflict with what I remembered of their origins, which was that they crossed into America from Asia, I began to read the odd book on the subject, and since it has a little to do with earlier climate changes, I thought to write a post on where I see the state of the current debate on the subject.
 When I started writing this I thought it would be relatively easy to just find a couple of references with the dates, from which the European influence would be easy to pick out. Well, after re-writing this post several times, I have to confess that was a bit naïve. It turns out that there are several controversial pieces of information out there, which mean that this is not the simple story I had expected to tell. And that one post is multiplying into a short series.
 For a start there are several different groups that might have made the migration from Siberia, although recent results from the Genographic Project suggest, according to Dr. Wells that their results favor the group that started in Mongolia.
 Then there is the question as to when the original group came. The oldest excavated archeological site in Alaska is at Swan Point and dates from about 14,300 years before the present (BP). But there is a site in Southern Chile, at Monte Verde which may date as early as 14,220 BP, and David Meltzer (in “First Peoples in a New World”) noted that there was some site evidence that might go back as far as 33,000 BP. 
The debate on when Europeans first arrived on the American continent has grown to include debate on both the shapes of the early weapons that were used, and the origin of the “Clovis Point” point shape that became most common, as well as the more recent debate on the origin of one of the genetic markers (the X2 haplogroup) that appears in members of a number of Indian tribes. 
 As I read more material, the different views became more complex to explain, and so one post is now morphing into three or more, particularly given the recent press release from UCSB on a paper that has evidence of a meteor strike which initiated the Younger Dryas cold period some 12,900 years ago.

These new data are the latest to strongly support the controversial Younger Dryas Boundary (YDB) hypothesis, which proposes that a cosmic impact occurred 12,900 years ago at the onset of an unusual cold climatic period called the Younger Dryas. This episode occurred at or close to the time of major extinction of the North American megafauna, including mammoths and giant ground sloths; and the disappearance of the prehistoric and widely distributed Clovis culture.

I do not plan on getting into the somewhat detailed and complex set of arguments as to what was the cause of the Younger Dryas. Some say it was caused by the collapse of a very large ice sheet covering North America that flooded the Atlantic and changed the circulation patterns for a while, others – as above – point to the evidence of meteoric impact. But it does give a point of reference relative to the time periods involved.  

 

Figure 2. Greenland temperatures over the past 20,000 years (From:
Quaternary Science Reviews Volume 19, Issues 1-5, 1 January 2000, Richard B. Alley, as referred to by Rodney Chilton 

However, even as I was writing this new version, there is apparently some new controversy over the temperatures that have been calculated in Greenland, with Anders Carlson at University of Wisconsin –Madison suggesting that the temperature drop may be smaller than that shown above (perhaps half). 

 A second original question related to the exact color of the paint that covered the Indians at the time of first contact, since it was reported that while wearing few if any clothes, Indians often were covered in some form of red paint. (And for now I’ll be mainly talking about the East Coast, though there are texts that cover the West.) Well this led into a discovery of the Red Paint People, which also feeds into the debate that apparently has been going on, with some intensity, among archaeologists, as to where that culture came from and where it went, some 7,000 years or so ago. 

 And then, as a more recent source, there is the discussion as to exactly how much influence, if any, that the Vikings exerted when they dropped by the coast some thousand years ago or so. So perhaps three different time frames, and maybe therefore three posts. 

 With no apology, this is the background upon which I, an admitted layman, am going to try and discern the current state of the evidence and belief, after having read recent books, articles and posts. It will include the odd thought on survival characteristics, and the possible creation of “journeymen” flint-knappers along the lines of the journeymen blacksmiths of which my great-great grandfather was one. But, since this post keeps increasing in length beyond this point, I will conclude this introduction with a few comments about the land that was above water at the time that the first settlers arrived.  

Figure 3. The Beringia land bridge from Siberia (Thinkquest), over which the PaleoIndians entered the American continent.  

Historians have long considered that North America was populated by a migration of some size from Siberia into Alaska, and then down into the body of what is now the United States. With the ebbing and flowing of the ice sheets the land route is thought to have first crossed on the dry land between the two continents, an area which has been given the name Beringia. From Beringia there has been debate as to whether settlers moved down the Mackenzie Valley, and thus inland, or down into the present USA along the coast. 

 Since that coast is now underwater it is more difficult to look for archaeological evidence of this alternative, but there is increasing evidence (including the DNA information which I will discuss in a later post) that the migration could have followed both routes. When these hunters arrived both mastadons and mammoths still walked on the continent as shown by the presence of stone spear points near the remains of some of these animals. (You needed spears to get through the skin, arrows – as Stanford and Bradley pointed out – work better when, in later years, bison were more prevalent). And next time I will about some of the controversy that these spear point shapes has brought into the argument.

The Citicorp Energy Projection - a Gentle Cough

Gasoline prices remain high, and Reuters recently noted that there are enough countries with civil unrest, technical problems and bad weather that there are around a million barrels a day of possible supply that are not getting to the market. . Yet with Saudi Arabia continuing to reassure that it is willing to pump more oil, if needed, there appears to be, superficially, little cause for supply concerns this year. By the same token, in the longer term, concerns over supply also seem to be increasingly discounted. For example Citigroup has just released a new report on Energy 2020:North America as the new Middle East. The report suggests that there is really no concern with future supplies of oil and gas, perhaps most clearly shown with this plot:

The Citigroup view of the coming energy future (Citigroup)

I would argue that the numbers for Saudi Arabia and Russia are difficult to realistically justify. For the Kingdom, which is reported to be producing 9.9 mbd, to increase production by another 2 mbd is optimistic, given the ageing of their primary fields and the decline in remaining volumes that I will discuss in future posts in the current series on that country. The projection of an increase in Russian production is a similar concern. With the decline in production from Western Siberia there is not enough new production coming from Timan-Pechora and Eastern Siberia to sustain existing levels let alone see an increase in production – a point that has been made by Russian officials in the past. However the real concern lies with the relatively unrealistic image that is being projected for US production over the next eight years.

North American shale plays (EIA map, cited by Citigroup)

The image that the above figure projects is that the country is covered in shale, all waiting to provide its wealth to the nation. But that is not the case and shale plays have been a hot topic for a number of years now. And while the map above shows a carpet of shale that has the potential to produce oil and/or natural gas it does not clearly enough distinguish the considerable difference between deposits that are presently economic, and those that are not. (The small number of fields that are labelled as prospective does not speak well for the future).

If one examines the prediction for future production it shows that overall US growth in production of all liquids will rise from some 9 mbd at the end of 2011 to 11.6 mbd in 2015 and then go on to a figure of 15.6 mbd in 2020. (Note that this includes natural gas liquids (NGLs), refining gains and growth in the production of biofuels). The contribution of the various sectors is broken down into:

Projected growth in US production (Citigroup )

In the Deepwater category Citigroup cite existing production from Atlantis, Perdido, Shenzi, Silvertip, Tahiti, and Thunder Horse. Future gains will then come from Big Foot, Gunflint, Hadrian, Jack, Knotty Head, Lucius, Moccasin, St. Malo, Stones, Tubular Bells and Vito. Tiber, Buckskin, Kaskida, Appomattox and Heidelberg. But the report sees gains in the Gulf of Mexico (GOM) total liquids as likely peaking in 2016 at around 2.2 mbd and the gains projected in the above table that might come beyond that as being an “upside potential” based on a change in regulatory factors and the ability of oil companies to bring their reserves on line.

Citigroup projection of future production from Deepwater (Citigroup)

Part of my problem with this approach is that it totally seems to discount the declining production and failure to meet target projections from existing GOM platforms which, among others, has been well documented by Jean Laherrère (here, here and here) and by Darwinian at The Oil Drum (TOD). Looking at the fields that Citigroup have cited it is pertinent to examine first their relative size, as Jean illustrated.

Discoveries in the GOM (Jean Laherrère)

In this context it might be well to remember that as a rule of thumb (from the Russian posts) a 500 mmboe field may produce around 120 kbd. However it should be noted that some of the GOM fields are having problems reaching their target, and that production is falling at a rate of around 20% per year, as Darwinian showed for the cumulative production of Thunder Horse Atlantis and Tahiti, which were projected to produce 550 kbd in total.

History of production from Thunder Horse, Atlantis and Tahiti combined (Darwinian )

With production having already fallen 300 kbd from projections, mainly through lower production from Thunder Horse and Atlantis, it is hard to see how to justify the numbers that Citigroup are using.

The Citigroup projection for Alaska anticipates possible gains from the Shell activities in the Chukchi Sea, although the exploratory wells have yet to be drilled and the geographical challenges to be met in bringing that oil ashore are not yet fully addressed. The Alaskan pipeline is currently flowing at around 609 kbd, which is high enough to prevent wax and ice build up, but with ongoing declines in production and problems arising once the flow falls below 600 kbd how long it can continue to perform satisfactorily is open to question. They cite heavy oil operations at Milne Point which has been declining in production, and West Sac which is a very heavy, cold oil which has raised considerable technical issues in achieving the production of around 15 kbd at present, with existing plans only adding 150 million barrels in total to reserves. The other source that is cited is to produce the light crude from the National Petroleum Reserve in Alaska (NPRA). Given that the bridge from Alpine into the Conoco-Phillips wells in the NPRA has just been approved suggests that an increase in production from the region is still some time away. Put together it suggests that the estimates for a 500 kbd increase in Alaskan production within the next eight years is not a reasonably likely occurrence.

Location of fields and development along the North Slope (Free Republic )

And the third source that Citigroup cite are the oil from shale deposits shown at the top of the post. They see growth of 2.4 mbd in oil production and 1.5 mbd in NGLs from the increase in production from natural gas. The production gains are broken down as follows:

Projected sources of oil from shale plays (Citigroup)

The plot, again, includes a large volume of “upscale potential” which might come from a change in regulations, government and oil company attitudes. I have written about some of the more realistic views of the possible future production of the Bakken and the Niobrara, the Tuscaloosa and the Chatanooga. In this regard it is worth noting that while Citigroup see production from the Bakken rising to around 1 mbd in 2016, and being sustained at that level through 2022, this is not the view of the folk in North Dakota who are monitoring well production and permits.

Anticipated production from the Bakken and Three Forks in North Dakota (DMR March 2012 )

It is instructive to this argument to note that Fidelity E&P has just celebrated reaching a production record of 3,500 bd in the Bakken which it derives from 58 wells. As they continue to run 5 rigs, and have been able to drill a long lateral horizontal well in 28 days they should be able to increase production this year, but they are fighting the rapid decline in existing wells, which requires that more wells be drilled every year, and that (as the better spots become drained) so the drilling activity must accelerate to sustain existing production.

Typical Bakken well production (ND DMR )

Production from the Bakken in North Dakota reached 546 kbd in January, and this production came from 6,617 wells which gives an average of 82.5 bd production from each well. Activity is such that some 250 wells are waiting on fracture services and rigs capable of drilling 20,000+ ft are at 95% utilization in the area. And prices of natural gas are down to $1.89/kcf. Bear in mind that, after a while, it becomes harder to find a spot where no-one has already been.

Map of wells planned and drilled in a section of the Bakken (DMR Presentation to Farm Bureau )

On the ground it looks more like this:


Well sites in the Bakken (Vern Whitten for DMR – Farm Presentation)

The North Dakota Department of Mineral Resources has a series of very informative presentations on the Bakken, including hydraulic fracturing, and the above were taken from the Presentation to the Piece Country Farm Bureau on March 15th.

Current plans anticipate that the Niobrara may reach 250 kbd of production by 2020. The problem, however, as Art Berman has skillfully pointed out is that, as the ND plot above shows, the current wells have a high decline rate, and production levels drop dramatically once the wells are brought on line. Art has explained the background to this for gas wells drilled into shale but the impact for oil wells, where the oil has a higher viscocity than the natural gas, can be significantly greater. Given that well costs are in the order of $10 million per well (depending on location DMR gives the ND price at around $8.5 million, and numbers for the Eagle Ford have been quoted at $8 million) the amount of oil that must be produced over the first few years to justify investment is significant. There are, for example, some 1,400 wells producing in the Eagle Ford play. The play produced 30.4 million barrels of oil in 2011, and is anticipated to add 200 kbd of production this year with the potential to reach 1.2 mbd by 2015. But the high decline rates mean that wells must be replaced rapidly to sustain those levels of production.

It is this disregard for the declining production from existing and future wells that appears to be neglected in the Citigroup study. Those plays which will yield rapidly in generating high initial well production will, in turn, be the first that decline significantly and need replacement. Yet replacement will, over time, have to be in poorer parts of the formation, requiring that multiple wells replace the initial producer, and so bounds on production will be reached, likely before the end of the decade. Citigroup anticipate that the risks in development of the shale plays, whether in Texas or California, come as much from an inability to transport the oil generated and from environmental policy, they see few geological risks – which is a pity, since it is the geology that will control production and its decline, and the ultimate profitability of these ventures.

And finally Citigroup see that cellulosic ethanol will come into its own this decade, and that it will provide half the 2 mbd of biofuels produced in 2020. Unfortunately the economics of large scale production that have led to failures of ventures to date have over-ridden the mandated production levels that the group cite as their foundation, and there is no indication that this will change in the next eight years.

In short, though this is an interesting exercise it is too full of “could” and thus will not make much of a useful contribution to meaningful discussion of future production.

OGPSS - Future Russian production from the Arctic

In the past few weeks I have been looking at the potential for sustainability in oil and gas production in Russia, now producing at a predicted recent peak of 10.36 mbd, when condensate is included. But the question increasingly becomes whether or not Russia can sustain these levels through this decade, as has been assumed by those suggesting that there will be no supply problems in the near future. In order to sustain this level of production, against falling volumes from the current major sources in Western Siberia (estimated as 300 kbd in 2010 ), Russia is so far relying on bringing new fields into production in Eastern Siberia and Timan-Pechora (as well as some increase in condensate as natural gas production continues to increase). However these developing fields, as a broad generalization, are at a size of about 500 mbd each, with an anticipated maximum individual production level of around 150 kbd. (Prirazlomnoye for example, which is coming on line has 526 million barrels in reserves, and will be producing at 132 kbd).

Prirazlomnoye drilling rig representation (Gazprom).

Since the high flow rates will likely not be sustained for long intervals, and declining production in Western Siberia will continue, so Russia will need to continue major programs of development to find further fields to bring on line later in the decade and beyond. In addition the declining production in other fields (which might increase overall decline in existing production to 5% or more, i.e. above 500 kbd) will add further pressure to sustain current levels, particularly given the criticality of oil and gas income to the Russian Government.

With much of the land already surveyed, the potential for large fields lies mainly offshore, and particularly in the various national continental shelves and the disputed underwater territory between them in the Arctic. It is a region where there are multi-national concerns and involvement, with the USGS having previously estimated that it is home to about one-fifth of the world’s undiscovered, but yet recoverable oil and natural gas resources, an estimate, at the time, of 44 billion barrels of oil and 1,670 Tcf of natural gas.

Map of the Arctic showing relative location of some development sites (Google Earth)

From the US perspective the US Bureau of Safety and Environmental Enforcement ((BSEE) seems finally willing to let Shell begin exploratory drilling in the shallow waters of the Chukchi Sea, although there has been a challenge to the recently awarded air Permit from the EPA. At the same time that the USGS is set to issue a new report that projects that shales on the North Slope may hold as much as 80 Tcf of natural gas and 2 billion barrels of oil, with initial drilling to prove the reserves anticipated to start this year. But those developments are on the other end of Russia, to the majority of current developments.

The recent discoveries by Statoil off the Norwegian coast and in the Barents Seas(at Skrugard-Havis, and Aldous Major South, show the potential that still remains in the North. Roughly a third of the world’s largest gas fields lie north of the Arctic Circle with Russia having significant reserves among them.

World’s largest gas fields (can you name the others?) (Shtokman )


Russia is therefore moving toward a planned program of development of the resources off its own continental shelf, where it is expected to be able to produce up to between 0.8 and 1.6 mbd of oil production and 18 to 20 bcf/day of natural gas. Part of the problem, however, is going to be cost. The new program is expected to cost some $216 billion, at a time when the investments in developing the current projects in Yamal and Eastern Siberia are also demanding large investment, if those goals are to be met.

Definitions of regions offshore (pertinent in future debates over who owns what in the Arctic) (Extended Continental Shelf Project)

TNK-BP are spending $12 billion to develop the Russkoe, Suzunskoe, Tagulskoe, Russko-Rechenskoe, and Messoyakhskoe fields in the Yamal region, with the hope that these can contribute at the end of this decade, and into the next, at a total level of around 300 kbd. Suzunskoye is targeted to begin production in 2016, running at around 100 kbd once on line. Russkoye is projected to start in 2017, and produce 150 kbd of a heavier oil. Tagulskoye and Russko-Rechenskoe will come on line in 2019. Messoyakhskoe is a joint project with Gazprom and (at $17.3 billion cost) will not come on stream until 2024, at 320 kbd. These fields will, however, feed into the pipelines that head East, to China, Japan and Korea.

Closer to Murmansk Exxon Mobil and Rosneft are exploring blocks in the Kara Sea anticipating that it may ultimately cost $500 billion to develop reservoirs in the difficult conditions with moving icebergs but for now expect that initial exploration and development will cost in the $10’s of billions.

Perhaps, of these fields it is the Shtokman natural gas field, which lies under the Barents Sea, 550 km north of the Kola Peninsula which has drawn most attention. Currently expected to start production in 2016, costs may well run over $15 billion.

Location of the Shtokman field (Shtokman Project)

Shtokman was discovered in 1988 (the name comes from Professor Shtokman who gave his name to the research vessel that found the field and contains an estimated 85 Tcf of natural gas, as well as around 400 million barrels of concentrate. It lies under 1,000 ft of water, with the interesting occasional problem of visiting icebergs that can weigh up to 4 million tons apiece. Planned to come on line in with an average production of 2.3 bcf/day, the supply (as the above map shows) half the supply is anticipated to feed into the Nord Stream pipeline for shipment to Western Europe, while the rest is converted to LNG and will be shipped out by tanker. Gazprom has recently increased the area of its license rights for the field, with a new date for commitment set for this month.

The current intent is to use a series of buoyed risers to connect from the wells to the surface, so that, should an extra-large iceberg appear the Floating Production Unit (FPU) can detach and move out of the way – should tugs not be able to divert it.

Artist’s concept of the layout for development of the Shtokman field (Shtokman Project)

The pipeline shipments are planned to begin in 2016, but the LNG shipments (some 7.5 million tonnes a year) will not start until 2017. The project is a joint venture between OAO Gazprom, Total S.A., and Statoil A.S.A.

The USGS has noted that there are considerable regions in the Arctic that have, as yet, been poorly explored. In 2005 they produced this map of the then state-of-knowledge:

Status of oil and natural gas evaluations around the Arctic (USGS)

From this they produced two maps showing the location of possible undiscovered deposits. The potential undiscovered oil deposits are shown below:

Potential oil discoveries and size remaining in the Arctic. (USGS)

The point however, is not that there is going to be no more oil, it is just, as the production schedules above illustrate, that it is going to be slow and expensive to develop that which remains. Over the next decade Russia will have to bring three or four new fields on line each year at around 100 – 150 kbd each, if it is to sustain production at current levels. It is somewhat difficult to see them being able to hold to that schedule, even for a year or two.

The "Relief of Nome" video

For those interested there is a 10 minute video of the travel of the ice breaker and tanker through the ice to Nome in order to deliver oil that has been posted on:

The Nome Nugget.

Progress of the Russian tanker towards Nome

Since the Russian tanker bringing fuel to Nome, and the accompanying ice breaker started out on Tuesday having sailed 53 miles on Monday, it seemed, with only 100 miles to go, that this drama was over. However it managed to move forward only 50 ft on Tuesday, due to the ice conditions. The ice breaker spent much of the time trying to break the tanker free from an ice ridge. I am therefore putting up the map again, and showing the relative position of the tanker and the ice breaker the Healy so that I can more easily add updates to the story.

Position of the ships (the icebreaker is the Healy) relative to Nome at 5 pm Tuesday (Central time)

And I know that Nome is really on the coast, but the name is more to identify the target. And for those who missed the earlier post which lies two stories down, Nome in Alaska is running out of fuel, and a tanker, supposed to deliver that fuel on the 7th January is having difficulty getting to the harbor. Due to storms earlier in the winter the normal fuel barge could not make delivery, and so the tanker and the sole remaining American active duty ice breaker were called into service. (The second ice breaker is out of service being overhauled). But the ice is thick and under considerable pressure - hence the ridges - and the pressure can also close the passage that the Healy makes before the Renda can move down it.

UPDATE: Here is the latest position of the Ice breaker (and thus I presume the tanker) at 11 am on the 11th. (Central time) It seems a little further away, but could be trying to find a better way through the ice for the tanker.



And here is a picture from the Healy Aloft camera of the Renda, date stamped 20120111-0101. (I think that the last 4 digits are GMT, since the pictures are going up every hour and the latest one - still dark, and the icebreaker starting to move (it has headlights on and is no longer pointing at the tanker) - is stamped 6 hours ahead of Central US time, which is GMT).



UPDATE 2 (4:30 pm 11th) It is now possible to see both the Icebreaker (the Healy) and the Russian tanker on the plot.

24-hours after the top map location, the tanker does not appear to be making much progress.

The Coast Guard has stopped predicting when the vessels may arrive in Nome, and even when they do there may be more problems. The icebreaker has too deep a keel to get into the harbor, and there is a 25-ft deep ice ridge that has been discovered across the mouth of the harbor. This means that the Renda will have to park off-shore and pump the fuel through a hose to the tanks. It has enough hose on board to be able to do this.

UPDATE 3: The Renda made a good run and is now 50 miles from Nome. There have been numerous ice ridges giving problems.

Position of the vessels at 10:15 pm GMT 12th Jan.

FINAL UPDATE Friday 7 pm GMT: The tanker and breaker have made good progress and are about 8 miles from the city (you can see some of the city lights in shots from the Healy aloft camera that were taken overnight.

Alaska, diesel, refining changes and Venezuelan exports

The Iditarod dog-sled race commemorates the time in 1925 when serum had to be carried from Anchorage to Nome to counter a diphtheria outbreak and dog sleds were the only way of making it through. A different problem is now beginning to face some of the remote villages in that state, as it becomes more difficult and expensive to supply fuel reserves to get them through the winter. With supplies restricted and expensive to deliver, prices can rise as high as $7.15 a gallon, gasoline was $5.44 in Nome earlier this winter. I was reminded of that this morning, as the Russian tanker, the Renda, turned back for minor repairs before essaying the trip from Dutch Harbor in the Aleutian Islands to Nome carrying a million gallons of diesel fuel (which powers the electric generators) and 400,000 gallons of gasoline. The fuel would normally have gone by barge earlier in the winter, but storms led to that delivery being cancelled. Now the tanker is being escorted by an ice-breaker since the last 300 miles of the 700 mile voyage will be through ice that can be 2 ft thick.

In other Alaskan news the November figure for oil flow down the Alaskan pipeline averaged 625 kbd, which gets the flow above the 600 kbd level which becomes a concern in winter, since it can lead to ice and wax build-up in the pipe. The December figure should be released soon.
UPDATE: As of January 9th the Renda is 140 miles from Nome, but is finding it hard to make progress through the ice, which is under considerable pressure. The "dynamic ice" has brought both vessels to an occasional halt, and the ice is thickening.

UPDATE 2: The ice has been more than 4 ft thick in places, and pressure is closing the passage some times before the Renda can make it through. It is difficult enough that the 2 vessels took a 12-hour break on Sunday night. They made 53 miles of progress on Monday, with 100 miles still to go.

Positiion of the ships (the icebreaker is the Healy) relative to Nome at 5 pm Tuesday (Central time)

Diesel fuel prices in the rest of the country are continuing to fall, as the latest TWIP notes, although at $3.70/gallon on average the price is still some $0.50 per gallon higher than last year.

Change in Diesel prices (EIA )

The US is producing around 5 million barrels of distillate (diesel) a day, up almost half a million barrels from last year, with domestic demand running around 4 million barrels. The remaining million barrels is being exported, largely to Europe and Latin America. The EPA requirement for cleaner diesel in the US has, as a perhaps unintended consequence, brought the fuel into compliance with European usage, and opened that market to the industry. Coming at a time when Russia is seeking to lower exports of low-sulfur diesel in order to keep domestic prices down, as the Export Land Model bites again, and with China banning exports, US exports have risen to exceed fuel imports.

Increasing exports is a move of necessity for some refineries since the continued decline in domestic demand for gasoline is hurting refineries. Sunoco, for example, is getting out of the business.

Decline in US gasoline demand over the past two years (EIA )

Note that there hasn’t been as much change in the domestic diesel market.

Demand for diesel in the USA over the past 2 years (EIA )

In fact Valero, one of the Gulf refiners, projects that the diesel market will continue to grow more strongly than that of gasoline.

Anticipated world growth in demand for gasoline and diesel (Valero Investor Presentation 2012 )

It has, as a result, been suggested that the additional diesel which will be generated should the Keystone XL pipeline be approved, will largely go to export. It has been pointed out that the Valero Refinery is in a Foreign Trade Zone, the diesel that is refined and exported will not pay taxes on it.

Export Market for diesel (Oil Change International )

Exports from the Valero Refineries (Valero Investor Presentation 2012 )

In passing I noted that Valero also seems to be doing well with its ethanol operations.

Recent income from ethanol for Valero (Valero Investor Presentation 2012 )

In the past 30 months Valero note that the EBITDA reached 90% of the purchase price of the 10 plants it runs, and which produce an average of 72,000 bd collectively. Collectively, in the USA, ethanol production has continued to increase.

US ethanol production (EIA )

And there was one final graph from Valero that I almost missed, but which is, in its way telling:

Venezuelan exports to the USA (Valero Investor Presentation 2012 )

It should be noted that this plot is just for refinery products, and that Venezuela has continued to export oil to the US over the past year. However the figures for the 4th Quarter show an average of 793 kbd, down 9% on last year, and the three monthly averages were October 916 kbd; November 748 kbd and December 715 kbd all significantly down on last year. In 2010 the US imported an average of 1.24 mbd, about half of Venezuelan production, but since Venezuela has fallen to become the fourth largest supplier to the USA with the average of 760 kbd much of the remaining Venezuelan production goes to China, and India. But should Venezuela continue to decline in overall production, that global shortfall will need to be made up from somewhere else.

OGPSS - Governor Perry, an Energy and Jobs Plan

Editorial Comment: I usually would not consider this a technical talk, but rather more political, but I have just about finished reviewing the potential for growth of the reserves in North America. In that context, as I delved into Governor Perry's recently announced Energy Plan, I realized that it followed fairly closely the recommendations of the American Petroleum Institute, and other Energy Alliances. Given therefore that it might be considered the "best shot" of the oil and gas industry to predict how to increase oil and gas production in the United States, I will treat it more as such a plan, and have removed my own comments on this post. (Though I may make some in a following post. I am also using his numbers rather than other values that might be available))

One of the relevant (to this site) facets of the current Republican debates at the start of this Presidential Race has been the Energy Plan that Governor Perry put forward the other day. Because it actually gets specific about where some of the projected 1.2 million jobs he anticipates adding to the American economy will come from, but given that detail has not got a lot of publicity, I plan to briefly review it here, together with some of the source documents that were used to generate it. Please note that this is not an endorsement, but rather an illustration of one of the plans that have been suggested. Here is the summary illustration.

The jobs anticipated by Governor Perry’s Energy Plan

The entire plan is available, as a 40-page pdf, and in its shortest summary version was condensed into

My “Energizing American Jobs and Security” plan will commence or expand energy exploration from the Atlantic coast to the western seas off Alaska. We will end the bureaucratic foot-dragging that has reduced offshore drilling permits in the Gulf of Mexico by eighty percent. We will tap the full potential of the Marcellus Shale in Pennsylvania, Ohio and West Virginia. We will unleash exploration in our Western states, which have the potential to produce more energy than what we import from Saudi Arabia, Iraq, Kuwait, Venezuela, Columbia, Algeria, Nigeria and Russia combined.

The Governor puts current U.S. consumption at roughly 19 mbd with domestic supplies producing around 7.5 mbd. The nation runs on oil with transportation using 72% of the oil, and 96% of the countries transportation fuel needs are supplied by oil and gas.

The Governor inserts a quote from Governor Jindal of Louisiana that states:

According to a recent study by IHS CERA, in 2012 alone the Gulf of Mexico could create 230,000 jobs, increase revenues and royalty payments to state and federal treasuries by $12 billion, and contribute some 400,000 barrels per day of oil production towards US energy independence if the federal government accelerates the pace of permitting activity to a level that reflects the industry's capacity to invest.

This quote refers to the report “Gulf of Mexico - Restarting the Engine” by CERA which tabulates the difference achievable between a slow permitting environment, and an enhanced one over the next two years, and uses it (in more specific detail) to develop the summary table:

Projected gain in opportunities in the GOM with an enhanced permitting process (CERA )

(It should be noted that roughly 94% of this in 2011, 97% in 2012 and all of the 2013 opportunities would be in the Deepwater offshore.)

In looking next at Alaska, the Governor sees the opportunity to develop the National Petroleum Reserve, with its 896 million barrels of oil and 53 Tcf of natural gas, as well as the Alaskan Outer Continental Shelf, (under the Chukchi and Beaufort Seas) which may contain as much as 10.2 billion barrels. The report by Northern Economics to Shell is quoted that anticipates some 55,000 jobs around the entire country coming from the development, with some 35,000 jobs being in Alaska. (Of this the breakdown would be 30,000 from the Beaufort UCS and 25,000 from the Chukchi Sea OCS. It is anticipated that the increased production will fill the Alaskan pipeline again, with jobs being generated to make the connections. Which is why the 1.2 million job figure is only reached over time. Wood Mackenzie produced a report for API that is also used as a reference for the Governor, and it shows the job growth (broken down a little by source) as:

Growth in jobs related to changes in Energy Plans (Wood Mackenzie )

I am assuming that the increased production from Alaska would fit in the “Increased Access” category. And please note that the Wood Mac report carries out to 2030, while the Governor is only talking of the jobs through 2020 (which is the 1.2 million number).

And while the Governor is largely discussing this plan in terms of jobs, this is, after all, an Energy site, and so I will also add the anticipated change in oil production that is foreseen from this change in the situation – again from Wood Mackenzie.

Gains in Production from changing regulations and access (Wood Mackenzie )

The jobs numbers were derived as a count of specific jobs generated in the industry, and then using a 2.5 multiplier to add their effect on the general economy. (This they consider to be conservative, given that in cases it might be as high as 5). The overall addition of oil to the national reserve is considered to be roughly 60 billion barrels of oil, broken down as follows:

Anticipated gains in reserves added through changes in regulation and access. (Wood Mackenzie)

The Governor is a little more conservative in the oil that he anticipates coming from the Atlantic OCS, anticipating only some 3.2 billion barrels of oil and 28Tcf of natural gas, as well as creating some 10,000 new jobs. He references a report from the Consumer Energy Alliance as his source for some of this information. Note that, in contrast to the Alliance, he only anticipates that drilling would occur offshore Virginia and the Carolinas.

Looking at increasing production of oil in the Western States, he cites the Blueprint for Western Energy Prosperity (site registration required) from the Western Energy Alliance. This projects that some 500,000 jobs could be created, along with the production of 1.3 mbd of oil and an additional 1 Tcf of natural gas from Western Resources.

The increase in oil production is anticipated to come from the Bakken fields (currently at 289 kbd and anticipated to increase to 650 kbd by 2020, and it also anticipates development of the Niobara formation in Colorado and Wyoming which, from sensibly zero, has recently started to be developed and is anticipated to produce some 286 kbd by 2020. However the total gain in production from the two, over existing production in the West, is anticipated to be 529 kbd.

Natural gas, transported through the Rockies Express and Ruby pipelines is expected to add 1 Tcf of production, which the Alliance shows divided between the Western States.

Anticipated future gas production from the Western States (Western Energy Alliance )

The Alliance makes the point, as does the Governor, that reaching these levels requires a reduction in legislation, and regulation, and improved access to federal lands.

Approval of the Keystone Pipeline (a topic of current debate) is expected to add 20,000 new jobs, which only leaves the allowance of increased development of the Marcellus and Eagle Ford shales (dependent on the allowed use of fracking the shale) to add respectively 250,000 jobs in the New York, Pennsylvania, Ohio region, and 68,000 jobs in Southwest Texas, and you have the Governors 1.2 million.

The jobs anticipated by Governor Perry’s Energy Plan

To achieve this the Governor proposes:

1. Immediately return to pre-Obama levels of permitting in the Gulf, followed by responsibly making more of the Gulf available for energy production.
2. Open the ANWR Coastal Plain (1002), National Petroleum Reserve Alaska (NPR-A), and the Alaskan OCS (Beaufort and Chukchi Seas) for development.
3. Open the Southern Atlantic OCS off-shore resources for development.
4. Immediately approve the Keystone XL Pipeline.
5. Expand on-shore oil and gas development in Utah, Colorado, North Dakota, Montana, New Mexico, and Wyoming, authorizing more development on federal lands.
6. Oppose federal restrictions on natural gas production, including hydraulic or nitrogen fracturing and horizontal drilling.

As I mentioned at the beginning I will make some comments on this, in light of my recent posts on North American Energy in a later post.

OGPSS - Can Alaskan coal be considered a reserve?

When I originally started to write about the Alaskan fuel sources I had intended to write only about the oil and gas reserves in the state, as I have done over the past few weeks. I was, however, since asked also about the coal in the state. And then, to reinforce the need to at least look at this fuel, there was this recent quote from the Chancellor of the University of Alaska-Fairbanks, Dr. Brian Rogers.

Rogers said he has heard objections to the construction of a coal-fired plant, but that it was the only cost-effective way to heat the campus in interior Alaska.

Until now, I have had only one chance to visit an Alaskan coal mine, the Usibelli mines near Fairbanks. Further honesty compels me to admit that I played hookey that day and took myself and my grad student off to have look at the Yukon River, the Dawson Highway and the Arctic Circle (certificates provided) instead. Not that the coal mining in Alaska is not important, and coal’s presence not also visually obvious, but I had seen a lot of strip mines in my time.

Coal outcrop Alaska (DNR)

The coal seams of the region are clearly rich, and thick, and near the surface, and so it is relatively easy to remove the overlying rock, mine out the coal, and reclaim the surface, after the mine has passed. I have written about the evolution of the mining shovels used to remove the coal and rock and the use of explosive to break the rock and coal in earlier posts, there are also, at the Usibelli Web site, video and animations to show how they mine the seams of coal shown in the outcrop above.

As the University Chancellor noted, coal provides a considerable power benefit to the state, though it also has created several bodies that are opposed to its growth, particularly the operation of a new mine at Wishbone Hill. This opposition comes in a region where, in the past, mining operations have removed some 7 million tons from some 18 different operations. But again, in this series I don’t want to argue the pro’s and con’s of individual sites. Usibelli currently mines more than 1.5 million tons of coal a year, with about 1 million tons being used domestically, and half-a-million tons is shipped to the Pacific Rim (mainly Korea). Usibelli make the point that one of the reasons that power costs in Alaska remain high is that coal plays a smaller part in power generation than it does in other states.

Relative electricity price in comparison with the coal mix in providing electrical energy (UCM )

If problems arise in bringing natural gas to more of the state, then coal’s fraction of the mix may well increase. Certainly the amount of coal within the state is vast. It has been suggested that there is as much as 5 trillion tons of coal in Alaska, some 40% more than in the lower 48 states combined. The coal is found in three provinces Northern Alaska-Slope, Central Alaska-Nenana, and Southern Alaska-Cook Inlet.

Coal regions of Alaska (USGS )

More recent estimates have had a tighter focus.

Previous coal resource assessments attempted to assess the total coal in the ground in the United States and Alaska, but those estimates tended to be high and included coal deposits that are either not available (contain coal beds that are too thin and (or) too deep to be economically mined using present mining technology) or that are not of sufficient quality to serve as a fuel for electrical power generation. Thus, a new assessment was required that focused on coal resources likely to be utilized in the next 30 years, which are for the most part coal beds currently being developed in existing mines or in areas that are currently leased in Alaska.

As a result the 5 trillion ton estimate from the 1977 study has been trimmed to consider just the 160 billion short tons which includes the coal defined in the quote.

However coal can only be considered a reserve if it is likely that it will be mined. At the moment it is the coal in the region around Fairbanks where the need is sufficient for coal to contribute to the state energy budget. But there has been exploratory activity in both other regions as well, and mines have existed in the past.

North of the Brooks Range, and lying over the National Petroleum Reserve, the Arctic Coal deposits hold the likely majority of the Alaskan coal. Unfortunately for those who would use it, it is not the easiest place in the world to reach, and operate in. And although there was coal mining in the region as far back as 1879 (when it was used to supply whaling ships) it is not active presently. BHP Billiton have been and looked, and while not abandoning the idea completely, do not currently seem active. On the other hand the state has been looking to approve prospecting permits in the Nanushuk region, which lies north of the Brooks Range, yet only just off the main haul road that runs up to Deadhorse and Prudhoe Bay. The request for a permit was approved by the state board, though there has been an objection from the Naqsragmuit Tribal Council (though I could not find a current web page for the Council).

However, in order for any coal to be mined above the Brooks Range, there has to be a viable method of transport. And though it has proved relatively straightforward to move coal by rail from the Powder River Basin in Wyoming, conditions are considerably different above the Arctic Circle, and the Brooks Range is a tad hillier than the Upper Great Plains. There is talk of moving the coal to the terminal where the Red Dog Mine ships out zinc concentrate, but that facility is only open from July to October - which might help China build up stocks in the summer, but does little for the global high winter demands for fuel. Further the haul road is not such that I can see it being able to handle heavy consistent loads of coal. (On the September day we went up that short distance a haul truck went off the road ahead of us on one of the many snow-covered bends that snaked up and down the mountains).

There is active consideration of a mine at Chuitna, which is just north of Cook Inlet, in the Southern of the three provinces. About 45 miles from Anchorage the project would mine up to 12 million tons of coal a year for an initial period of 25 years. At present it appears that the Division of Mining, Land and Water is awaiting an updated proposal before moving ahead to make a ruling, possibly in a preliminary form next year.

Put altogether, although there is a lot of coal in Alaska, in relative terms it is unlikely that any significant volumes of that resource will be brought to the market in the near future. As a consequence, unless and until the demand pattern changes, (and I think that it likely will) it is impractical to think that Alaskan coal will remain more than a resource. Further, given the need for a supporting infrastructure itseems unreasonable to expect that even after global demand starts to rise, that the coal could come to the market, and become a reserve in less than an additional 5 – 10 years.