Bit Tooth Energy

OGPSS - The oil in the Western Siberian Basin

2012-01-25T23:21:00.012-06:00

Time marches on, and as I noted in an earlier post, the declining fortunes of the Romashkino and other oilfields in the Volga-Urals Basin led into the development of the fields of Western Siberia, where even today, some 40-years after it was discovered, just over 60% of Russian crude is still being produced.

Russian production in 2009, broken down by region (the total is 10.48 mbd) (EIA)

Back in 2007 production was at 70% of total Russian crude oil production, with a daily production of 7 mbd so that there already changes in the mix occurring. At its peak, in 1980, Samotlor, the largest field in the region, was producing at 3.4 mbd, out of a Soviet production of 12.5 mbd. Samotlor is thus ranked 7th in the world in terms of original oil reserves, and, as a comment on the times, while production has fallen to 750 kbd, it still ranks 6th in the world in terms of daily production. Initial reserves stood at 27 billion barrels of oil, though this was not initially evident, when the field was discovered in 1965. Water cut has increasingly taken its toll of the field, and now runs at around 90%.

Gas Flare over Samotlor in the marshes of West Siberia (Geotimes)

It took some persuasion to get the Soviet oil industry to move that far East. The new fields were some 600 miles further East than those of the Western Urals, and the country was divided between taiga and swamp. There weren’t a whole lot of people, either.

The different regions of Russian oil production (Petroneft)

Much of that has changed, with the center of the oil industry now located in and around Khanty-Mansiysk, a settlement since 1637, but mainly built after 1931 when it became the capital of the Ostyako-Vogulsky National Okrug. It was given its current name in 1940, and became a city in 1950. As a sign of the changing times, the provincial budget from oil revenues was $4.5 billion in 2008.

Oil seeps had been reported in the outcropping of rocks along the Ob River since the seventeeth century, and I.M. Gubkin, the founder of petroleum geology in the Soviet Union, had predicted the presence of oil as early as 1932. Serious exploration began in 1954. In 1962 a well drilled near Tazovsky produced natural gas at a flow rate of a million cu m (35 mcf) a day and the Tazovskoye oil and gas field had been found. Originally it was developed as an oil field, but more recently its natural gas potential has been more fully recognized as has that of the entire Yamal Peninsula. (And in the same time that 70% of Soviet oil was coming from Western Siberia, so was 90% of their natural gas.)

The oil and gas fields of Western Siberia (after Grace – Russian Oil Supply)

Tazovsky by Vghik (Google Earth)

The northern part of the West Siberian Basin (which, as Grace points out, covers an area about four times the size of France) has been where the most recent exploration has taken place, but was further south, and east along the Ob River that the first three major fields Fedorovskoye and Mamontovskoye near Surgut, and Samotlor which lay further East near Nizhnevartosk, were found between 1963 and 1965. An oil pipeline was laid in 1967, allowing year-round production. From the beginning construction and development was a problem, given the local geography and ways had to be found of getting production equipment into the marshy ground and getting the oil and gas out. For many years the Ob river was the main highway.

These three fields underpinned Soviet oil production through the 1980’s, and with the 14 fields that were added in the second generation, the 7 that came on line for the third, and the 8 that made up the fourth generation, they kept the Soviet Union well supplied until its collapse at the end of 1991.

Crude Oil Production from Western Siberia (Grace – Russian Oil Supply)

Over the past decade these fields have been rehabilitated and raised production by more than 60% over that at the depths of the crash, after the dissolution of the Union.

Fedorovskoye is run by Surgetneftegas, a company that drilled 1,403 wells in 2011, including 708,000 ft of exploration. In 1993 the company was allowed to become an open joint stock company. The field, which peaked at a production of around 1 mbd in 1983, is now referred to as the Fedorovsko-Surgutskoye and with a current production of 400 kbd it ranks 14th largest in the world. As a sign of the times, perhaps, the new fields that Surgetneftefas are developing are, however, in Eastern Siberia.

Mamonskoye is run by Yuganskneftegaz and was acquired by Rosneft in 2005. It too peaked at around 1 mbd, though in 1986. The company estimates that in the Khanty-Mansiysk region its 30 license areas still retain a reserve:annual production ratio of 24 years.

This includes the Northern part of the Priobskoye field, the “Pearl of West Siberia,” discovered in 1982, and brought on line in 1989, and the Prirazlomnoye field which is the Russian offshore (a third future topic). The Priobskoye field was producing at 650 kbd in 2009, when it was ranked as the 8th largest producer, with plans to further increase production through 2013.

Fields around Khanty-Mansiisk, including Priobskoye (JPT)

The Southern part of the Priobskoye field is being run by Gazprom Neft the oil branch of the Russian gas company. In 2007 Rosneft produced an average 550 kbd from the Northern half of the field, while Gazprom was producing 127 kbd. Gazprom has about 40% of the field. Production has been helped in more recent times with the use of Schlumberger’s advanced down-hole motors and technology.

Down-hole motors used at Priobskoye.

Also in the region, and similarly just coming on line are the wells of the Salym Project, which, last Sept 25th reached a production record for them of 177 kbd. The oilfields include West Salym (reserves estimated at 630 million barrels; Upper Salym (reserves estimated at 150 mb) and Vadelyp also at 150 mb.

One of the problems of sustaining production, even given this wealth of opportunity, lies in the need for considerable investment to make it happen.

Coburn(pdf) has pointed out that only 60% of the investment needed in 2009 to sustain the industry was forthcoming, and suggests that the $110 billion needed for exploration and development before 2016, and most of this will have to be spent further East in Siberia and Sakhalin (which will be visited in future posts). He further notes that Lukoil have suggested that $1 trillion will be required to sustain production at current levels. This will include a further production from Western Siberia to the tune of 45.5 billion barrels. Given that most of the larger, older fields are showing depletion levels of 70% or so this is going to have to come from developing a larger number of smaller fields. But that will take an investment that is still doubtful, though Lukoil are investing some $24 billion in downstream operations, showing that they are anticipating getting the oil from somewhere.

Given the size of the Basin, I have not spent enough time today on natural gas too much of which is still flared, so I will return to the region again.

OGPSS - future promise of production from Romania

2012-01-18T22:55:00.014-06:00

There are violent protests taking place in Bucharest, Romania which carry with them the threat of destabilizing the government, as we have seen in countries which lie further south. But while countries involved in the “Arab Spring” have oil and natural gas that are being exported, Romania is no longer a leader in production and export of petroleum products, but now imports them. Yet back in 1837 it was reportedly the first country to have an oil industry, reaching a production of 1719 barrels a year. It was also, in 1900, the first country to export gasoline, at a time when it was producing some 5,000 barrels a day. That made it the then third largest producer in the world. But by the 1930’s the country had fallen to seventh place, even though Romania was still the second largest producer in Europe, behind the Soviet Union.

By the time of the Second World War the oil fields of Ploetsi were underpinning the operations of the German military machines, providing an estimated third of that country’s need. Attempts to bomb the fields were prolonged and, though they were not always successful and the fields and refineries continued to provide fuel for most of the war, the continued bombing finally got production down to 7% of capacity.

Location of Romania and Ploetsi (Home of Heroes)

Following the war the region fell into the Soviet zone of influence. Production picked up, and rose until 1980, following which it has declined, until fairly recently.

Annual production and discovery (Jean Laherrere)

More recently, as demand has continued to rise, the country has had to rely, increasingly, on imports.

Recent Romanian oil balance (Energy Export Databrowser)

Similarly peak natural gas production was also around 1980, with the country, since then, barely keeping a declining supply in tune with falling demand.

Recent Romanian natural gas production (Energy Export Databrowser)

(The country started nuclear production in the late '90s and has significant coal production)

The nine oil fields in the Ticleni region, one of the older oil producers in the country has just changed management hoping thereby to increase production of 4,500 bd from some 300 wells to over 6,000 bd.

Seismic exploration, introduced after WW II, helped make the majority of the discoveries that led to peak oil production in 1976. It has been the use of 3-D seismic that has revealed much of the potential that had not been developed in the past.

Romanian oil production and peak (Petrom)

Petrom was privatized in 2004, and began paying a dividend in 2010. Exploration offshore began in 1975, with oil production starting in 1987, from the Lebada East Field. By the end of 2010 total production, from a total of 250 fields, had risen to 174 kbd.

Encouraged by recent activity, Melrose has begun investing money in the offshore Black Sea. This follows a recent trend in which the Deepwater Champion entered the Black Sea to drill off Turkey, last March. Just this month it has moved off the Romanian coast, after having terminated work at two sites off Turkey. Drilling is under an ExxonMobil/Petrom partnership, with Exxon Mobil providing the funds. If the initial well proves out, plans are to invest more than $3 billion in developing the prospect.

The historic fields have all been onshore around Torcesti for oil and Mamu for natural gas, while the new fields offshore are such as the Delta, which is in deeper water. It is currently anticipated that crude oil reserves are around 420 million barrels, with some 2 Tcf of natural gas, though there is potential for more.

Map of the Black Sea showing the relative position of Romania. (World Atlas)

There is still an ongoing efforts to redevelop mature oilfields in the country, steam injection will be tried this year using long horizontal holes, rather than the vertical used to date, in the heavy oil SUPLAC field in the West of the country. Water injection is to be tried in the OPRISENESTI field in the East, and polymer injection is being considered for the VIDELE field in the South. VIDELE was earlier the site for a successful World Bank funded project that used in-situ combustion to try and reverse the declining production of this and the BALARIA fields. The treatment was intended to increase ultimate oil recovery from 15% to 39% of the OIIP. In 1998 Supalcu de Barcau was the largest in-situ combustion project in the world with about 9,000 bd of production.

More recently the discovery of a new reservoir in the TOTEA gas field, and a new well currently on test, has the potential to be the largest gas find on shore in six years.

However much of the future looks deep offshore in the potential of fields such as the NEPTUN. (Though the company is hedging its bets by also building a wind farm).

Romanian oil and gas fields (USGS)

The new exploration and development is shared between Petrom and Romgaz, who have 55% of the natural gas sites in the country.

Romanian concession holders (Romanian National Agency for Mineral Resources)

Offshore production from the Histeria Block

While the current production from the Delta IV field is on the Continental Shelf, the new exploration is ranging into the deeper waters of the NEPTUN field, where the Deepwater Champion program is scheduled to last some 90 days. Water depth fluctuates from 160 ft to 5,500 ft over the field, but the first hole has been spudded in 3,200 ft of water. The field is a hundred miles offshore, and has undergone the largest 3-D seismic survey in Romanian history prior to the drilling program.

Deepwater Champion (Transocean)

The maritime dispute with Ukraine was settled in 2009 setting up the bidding offshore, and estimates for the Neptun field run up to 3 Tcf of natural gas and 73 million barrels of oil. Unfortunately even if these discoveries pan out they are unlikely to have much impact on the problems in Bucharest, although perhaps by the time that oil is brought ashore, they will be over and production might be sufficient to help with the budgets of the country. But that thought includes a lot of possibly wishful thinking . . . .and that future will not be here for several years yet, even if it should come to pass.

The changing sources for renewable liquid fuels

2012-01-14T18:05:00.002-06:00

While it may be way too early to declare a final winner in the race to find replacement renewable liquid fuels to replace the jet fuel and diesel that power so many of the vehicles in the world, there are some indications as to the technology that just might end up coming out ahead.

The results that are starting to appear also show that sometimes there is a disconnect between what the Government wants and considers possible and the real world. The concern over climate change (not peak oil) led many Governments around the world to mandate that propulsion fuels include a growing percentage generated from a renewable source. Six years ago I was in St Louis for the Renewable Energy Conference with its great emphasis on cellulosic ethanol. President Bush came to bless the endeavor, and much was made of it being the time to start building plants. A short while thereafter I started looking into the generation of biodiesel from algae, and brought up the, to me, logical suggestion of growing it underground. (That idea still gains me the occasional pat on the head). Some of the early reviews of the technology were not good, but nevertheless the Defense Advances Research Projects Agency began funding the development of algae, particularly as a source for jet fuel.

Time passed, and the development of the new fuels took quite different paths.In order to encourage the change to renewable fuels the EPA mandated that motor fuel include 100 million gallons of cellulosic ethanol in 2009, 250 million in 2010 and 500 million by 2013. (This is on the way to a target of around 2 mbd by 2022.) Some of the original companies to seize on this opportunity started out with too great an ambition. Range Fuels, after some $156 million of Government loans from the Bush Administration, closed its doors this past year, unable to make the product it had promised. When it became obvious that the initial targets would not be met the mandated volumes were lowered, so that, for example, this year the industry target is 8.5 million gallons. But still the Government will fine companies, for not using a fuel that doesn’t yet exist in the volumes needed to meet those quotas.

Two firms say that they will be able, in time, to produce significant volumes; POET is beginning construction of a plant in Emmetsburg, Iowa that is targeted to produce 25 million gallons a year from 700 tons a day of the left-over material from corn fields after the corn is removed. They have currently stockpiled 61,000 tons of stover for use this year. There is some concern however over the long-term Biomass Crop Assistance Program which is supposed to help with funding. (DOE is to provide a $105 million loan). However the Scotland S.D. pilot plant can only handle a ton a day of material (turning it into 80 gallons of ethanol at a cost of around $3 a gallon), and so the rest is to be burned as a fuel at the ethanol plant in Chancellor, S.D. (This is a corn ethanol plant.)

A second plant will be built at Kinross in Michigan, by Mascoma following an agreement with Valero, and the award of $80 million from the Department of Energy. The plant is intended to generate an annual flow of 20 million gallons (1,300 barrels/day ) of cellulosic ethanol from hardwood pulp. The process is based on the use of engineered micro-organisms to the necessary saccharolytic enzymes and then converting the sugars released by those enzymes into the desired end-products. The process is knows as Consolidated BioProcessing (CBP) In the meanwhile they are also licensing a technology for improving the performance of corn ethanol plants. To date, therefore, the promise of cellulosic ethanol has not been met.

Other sources for liquid fuels have been also been tested, and some – particularly the use of vegetable oils, either pre or post use in fast food chains – have found some niche in the market. Alaskan Airways are using an 80% conventional 20% cooking oil derived mix. At the moment the cooking oil derivative is six times the cost of conventional fuel and Dynamic Fuels is the only commercial source with the plant having a capacity of 75 million gallons per year. The are now working with Solazyme to meet a target delivered volume of 450,000 gallons of renewable fuel, and that brings the focus back to biodiesel from algae.

By 2010 DARPA was already claiming that the contractors it was working with had shown the promise of producing algal biodiesel at a price of $2 a gallon. Following that step, the US Navy has begun trials with oil made from algae. In the set of agreements that have flowed out of the initial success, and led to the 450,000 gallon agreement, the U.S. Navy has taken delivery of roughly 75,000 gallons of biodiesel for testing in the fleet. And while the US Air Force is continuing trials of jet fuel made from camelina as the search for replacement renewable fuels continues. Beyond camelina (which has some problems finding a suitable home for large volume growth) commercial airlines are looking at algae sourced alternatives, with a United Continental flight having used a 60% conventional 40% algal sourced mix on a flight from Houston to Chicago. The algae-based fuel comes from Solazyme, which went public last spring and the company and has signed a non-binding letter of intent with the airline to sell them 20 million gallons of bio-sourced jet fuel starting in 2014. Interestingly the plant uses “indirect photosynthesis” to grow the algae, rather than open ponds. Robert Rapier has described the technology that they use. By using algae that do not require sunlight they can generate the fuel in bioreactors where the process can be better controlled. Gail Tverberg first wrote about the company in 2008.

Despite the opportunities that the fuel market presents, it does not, however, at the present time, provide much profit to a company, since it is costing about as much to produce a product as the market price will bear (around $3 a gallon). Thus it is still more profitable for the company to use the algal product in an earlier form as a triglyceride that can then be used in cosmetics and other chemical stocks. But, in contrast to the problems that cellulosic ethanol continue to have, I must admit to a quiet smile as I see the success that algal-derived fuels are starting to achieve.

Now if I could just get them interested in nice, constant temperature locations for their plants, with much of the infrastructure, walls, roof and floor already in place, and relatively little cost for development, my original projections just might . . . . . . .

Progress of the Russian tanker towards Nome

2012-01-10T23:45:00.015-06:00

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.

OGPSS - Oil and Natural Gas in the Volga-Ural Basin

2012-01-09T23:44:00.010-06:00

In the last post on the oil and gas fields of the Northern Caucasus, I commented that one of the reasons that these older oil and gas fields were being further developed was due to the introduction of advanced Western techniques. As John Grace points out in “Russian Oil Supply” another reason that there are fields left to develop is due to the philosophy by which the Soviet government marshaled resources to keep the Union supplied with oil for domestic and export use. Because of its centralized nature, as the resources in one region declined, so the financial support and technical equipment were removed and taken to other parts of the country, where a more plentiful supply source was available. This frequently left smaller fields behind, and removed the incentive for further exploration in the older regions.

The first region to see that removal of support was around Baku, and then the North Caucasus, as more plentiful resources became evident up in the region around Almetyevsk, in what is now the Republic of Tatarstan. The region lies considerably north of Volvograd (Stalingrad) and further east, though it still lies on the banks of the Volga, though also just to the West of the Ural Mountains, and thus the more popular and general description is the Volga-Ural Basin.

Relative location of Almetyevsk, showing the Volga (black line) Stalingrad (now Volvograd), and the Caspian. (Google Earth)

The Volga-Urals Basin is now recognized to be extensive with the USGS estimating that there remain some 1.5 billion barrels of oil, and 2.3 Tcf of natural gas (at the mean) left to be discovered and produced.

Extent of the Volga-Ural Basin (USGS )

Prior to the Second World War, the region saw little development. Tar pits within the Basin had indicated the presence of oil, and Grace has pointed to outhouses exploding around the town of Orenburg, as natural gas from the underlying field collected in the buildings, as the first indicator of the presence of that field. But the fields all appeared to be small, and with enough production from Baku and Grozny to meet existing needs, there was little initial incentive to develop what seemed to be a series of small shallow fields.

Oilfields of the Volga-Ural Basin (Russian Oil Supply)

With the German advances into the Caucasus, that oil became lost or more difficult to bring north, and the relative security of the Volga-Urals meant that a greater effort was made to bring those fields on line. Production had reached 55 kbd in this “second Baku” by the end of the war. The first break had come with the discovery of the relatively shallow oil field at Tuymazinskoye in 1937, but it was not until they deepened one of the wells into the lower Devonian layers in 1944 that they hit the more productive reservoirs and the potential of the region became evident. In 1943 a test well had been sunk at Shugurovo and flowed at 140 bd from a reservoir at 2,000 ft. With the knowledge of the deeper reservoirs a third well in the region, near the town of Romashkino was drilled down to 6,463 ft, penetrating the casing on July 10, 1948. Because of formation damage the well was slow to produce, but within a short while was up to 876 bd. Holding 17 billion barrels of oil, and thus the largest oil reservoir discovered at the time, the Romashkino field (which included the well at Shugarovo) had been tapped. In time another seven fields, each of more than a billion barrels, were added to the inventory for the Basin.

The deeper Devonian beds required a number of innovations to produce at the levels that Moscow was requiring. The first of these was the development of the down-hole turbo drill. Russian steel making was not on a par with that available in the West, and the torque requirements for drilling the harder and deeper rocks were a challenge, overcome by putting the turning motor at the bottom of the well. The second problem that arose was in maintaining well pressure as the oil was removed. The use of contour water flooding evolved from the initial Master Plan in 1956 and was successively modified to perimeter flooding, so that by 1960 the basin was producing at 2.9 mbd, comfortably exceeding the target 1.2 mbd. Romashkino itself peaked at just under 1.6 mbd in 1968 and began to decline in production in 1976. As production declined, so the water cut also rose and by 1993 production was down to around 300 kbd, with about 85% water cut.

Production of oil from Romashkino (Russian Oil Supply)

Overall production from the Volga-Urals Basin includes some of the fields that lie outside of Tatarstan, as a result the decline of the Basin was a little later than that of the main field within it. For example further to the East lies the Arlan field in Bashkortostan, run by Bashneft. That too, however, is now in decline. In its 50-year life it has produced, with the Shkapovo field, over 4.7 billion barrels of oil. The overall basin produced from over 800 discrete fields.

Production history of the fields of the Volga Ural Basin (IHS via Dave Cohen )

More recently the EIA reported that the Volga-Urals Basin produced 2.03 mbd in 2009, while the Northern Causasus produced some 800 kbd.

Romashkino lies in Tatarstan, and the Tatneft Company had been formed to develop the oil in the Republic, of which some 6.3 billion barrels was in reserve. Realizing that their geography precluded independence, they became an associate subject of the Russian Federation, and Tatneft was privatized. Through helpful arrangements with the local government production, which had declined through lack of investment, was brought back to 465 kbd for the region, and has held at that level, through the collapse of the ruble. As the economy was restored the company began to expand, and has helped, for example, Kalmykia to develop their resources. (The Caspian oilfields that are now being developed lie off shore Kalmykia).

With over 15 billion barrels now produced from Romashkino more advanced techniques are being used to improve recovery of the remaining oil. These include the use of carbon dioxide injection, which has improved some production by as much as 12%.

Because Volga Urals oil has a high sulfur content (around 2.5%) this has, in the past, led to it being blended with West Siberian oil prior to refining. As the resource has declined the oil that is left is increasingly heavy, merging into the Melekess oil sands.

(Russia in total is estimated to have around 246 billion barrels of bitumen in sand formations, though most of it is in Eastern Siberia). The USGS has estimated that, at present, some 13.4 billion barrels of the Melekess oil is technically recoverable. Working with MicroPro GMBH
the bacteria Clostridiae has been tested as a means of improving production.

Improved flow conditions in the reservoir and increased gas/oil ratios led to an enhanced net oil production by 50% to 65% without changing production regime. The water content of the entire field was reduced from 74% to 57%. Between 1992 and 1995 the MEOR treatment resulted in an additional MEOR oil production of 4,200 ton (26,400 bbl)

Whether the small fields that remain in the Volga Ural Basin will be developed in the short term (as they likely would be by small independents were they in the West) appears to be currently less likely as both Tatneft and Bashneft see better returns by investing outside the region than within it. They are also reputed, by Grace, to retain a lot of Soviet-era infrastructure and thinking within the companies, which may also reduce the effort to invest in the smaller fields. It is difficult, therefore, to see the region have much increase in production from current levels, but rather it may continue a decline into the future.

In regard to natural gas, down by the border with Kazakhstan lie the natural gas deposits of the Orenburg field (of exploding outhouse fame). Production began in 1974, reaching a steady state of production in 1979, holding a 48 bcm production per year until 1984. In order to maintain pressure water flooding was used, and its influence on the production of a typical well can be seen below. Overall production has since fallen to 18 bcm per year.

The use of water pressure to sustain production from a well in the Orenburg field (Ivanov)

More recently the field has changed to the use of initially horizontal wells, and then, since 2009, the use of multi-laterals in order to sustain production and increase reserves, still considered to be around 280 bcm of natural gas (9 Tcf). This is a little more than the EIA estimate. However, given the increasing cost of developing this, when set against the much larger volumes that can be found in other parts of Russia (not to mention Kazakhstan and Turkmenistan to the south) it is reasonable to assume that the region will continue to decline in natural gas production also.

Alaska, diesel, refining changes and Venezuelan exports

2012-01-05T16:54:00.017-06:00

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 - Oil production from the North Caucasus

2012-01-05T00:09:00.006-06:00

When the topic of Peak Oil is raised, one of the first responses that is often heard from those trying to explain why a peak isn’t going to happen, at least in the short term, is that technology will come up with new answers. These will allow greater production of oil through access to previously unavailable reservoirs, and an increase in the amount of oil that can be economically recovered from them. It is an argument that has had demonstrable success in the past. An earlier post showed that innovations in technology allowed the region around Baku in Azerbaijan to remain one of the centers of oil production since the time of the first Russian oil pipeline in 1878 through today. The statement is, unfortunately, not universally or ultimately true, but it does provide an introduction to today's topic.

The change from cable-tool drilling to rotary drilling resurrected production in the Caucasus after the Soviet Revolution, and the growth of production to include the areas of the North Caucasus also brought other fields on line. These were initially the fields around Grozny and Maykop and in combination they raised production to around 622 kbd at the start of the Second World War. In more recent times it has been, again, the introduction of the latest Western technology that has helped sustain Azeri production, and new technology is starting to improve and sustain production in the North Caucasus.

The countries, and some key locations, in the North Caucasus (after a map from the BBC News )

Georgia, through the port at Batoum (now Batumi), was one of the early exporters of oil from Russia to Europe.

The production of the northern Caucasus increased from 100,000 poods in 1877 to 1,656,000 poods in 1889. In the latter year Terek furnished 275,731 poods, Elisabetpol 3,000 poods, and Daghestan 3,955 poods, while in the Signakh field, near Tiflia, 55,296 ppods were obtained.

Note: poods were the early Russian measure of production and that there are 8.33 poods per barrel.

In the period from 1884 to 1914 Georgia exported a total of around 165 million barrels of oil of oil. This oil increasingly came from the fields around Grozny (now in Chechnya, Russia) and later from the fields around Maykop (now in the Republic of Adygea in Russia), even though there were considerable signs of oil in Georgia (oil sands near Signakh west of Tbilisi and gilsonite in the Guria district). The Grozny fields were producing about 18% of Russian oil (with the rest coming from Baku) in 1915.

Following the collapse of oil production with the Revolution and the end of Western ownership, it was the use of rotary bits that allowed production to ramp back up, supplying a seventh of Western European imports (John Grace – Russian Oil Supply), and providing needed income to the Kremlin.

During the Second World War the region became a target for German occupation, given that oil from the region was providing a third of German imports in 1940. (Daniel Yergin – The Prize) However although Operation Blau reached Maykop, the smallest of the three main oil concentrations, the oil fields had been destroyed, so that only around 70 barrels per day were left available. The German Army soon became bogged down in the siege of Stalingrad, to the North, and did not reach Baku.

The oilfields around Grozny were first developed in 1893, with 386 wells by 1917 and grew steadily. The Grozny field peaked at around 154 kbd in 1932, while the output from the entire Chechen-Ingushettia region, which fed to the three refineries at Grozny, fell to around 148 kbd by 1980 and to106 kbd by 1985. Grozny then became more of a pipeline terminal.

The first major pipeline, running from Grozny to the refinery at the port of Tuapse had been built in 1927. The pipeline was later extended to also pick up oil from the Maykop fields, and fell into disuse in 1968 when it was replaced with more modern pipelines to the rail terminals and oil terminal at Tikhoretsk, and that pipeline is now being increased in size to carry 250 kbd of oil. Overall the terminal which takes oil from the North Caucasus and Kazakhstan and forwards it to Novorossiysk, on the Black Sea, has a maximum throughput of 640 kbd. Part of the pipeline carried oil initially from Grozny to Baku, but with the onset of the Azeri-Chirag-Guneshli project flow is now reversed.

Grozny has had an unfortunate history with the surface structures being largely destroyed, first in the Revolution, and then by German bombers. The town and facilities were rebuilt and became the center of the local oil business. The Chechen wars of 1994-96 and 1999-2000 then largely destroyed the center of the city. Similarly the oil wells in the region were impacted, in the 1994 war only 100 wells, out of 1,500, were operating by the turn of the year.

The more recent finds, that are resurrecting the promise of the North Caucasus come, however, as do many recent discoveries, offshore. Lukoil carried out a series of explorations in the North Caspian between 1999 and 2005, finding six large fields off the Dagestan and Kalmykian coasts. These were Khvalynskoye, Yuri Korchagin (50 kbd) , Rakushechnoye, Samatskoye and Filanovsky. The fields were initially assessed at around 4.7 billion barrels of oil, with the Valdimir Filanovsky being claimed as the largest new oil reserve discovered in Russia in 20 years. The initial well flowed at 6,400 bd with reserves estimated at 600 million barrels, with 34 billion cu. m. of natural gas. Overall North Caspian production was anticipated to peak in 2013 at 170 kbd, but Filanovsky alone, due on line in 2014, is now anticipated to reach 210 kbd with production initially coming from 11 directional wells with horizontal completions. To reach these levels Lukoil will be investing some $22 billion.

Location of the Korchagin field (Lukoil )

Looking further into the future Lukoil are expecting to be able to further develop the North Caspian to reach a production capacity of 320 kbd of oil and 13 billion cu m of natural gas per year, by 2020. Lukoil expects that the increase in production will be able to offset declines that are anticipated from Western Siberia by that time.

The introduction of modern technology is thus helping to increase production from regions that were, at one time, thought to be exhausted. It should, however, be remembered that horizontal wells have now been around for some 30 years. One wonders what ,so far unpublished, new technologies will appear to help within the decade, since to have an impact they must be widely accepted and adopted, and I don’t hear of much.

Design of the Filanovsky platform (CNGS Group )

And some "change of year" thoughts on climate change

2012-01-01T14:43:00.004-06:00

The year has been quite mixed for those who follow the climate change debate. Those who have developed the CO2/temperature theories and predictions on which much Government action has been based, remain largely as much or more in control as they have been in the past. Governments in place, whether in Europe, Australia or the United States are sufficiently convinced that the theoretical predictions of future higher temperatures are correct that quite significant changes in fuel policy have been put into place. This change is now placing greater reliance on renewable power sources, with natural gas seen as the back up and replacement power source during the transition away from historic fuels. And the historic fuels of the late twentieth century, coal, oil and nuclear power are being consigned to the scrap yard as fast as legislation and political power can move them.

Yet at the same time the economic realities are biting into the renewable energy business. In Spain the largest solar power station is just coming on line but the funding to continue the transition (which some of us might designate as the experiment) is beginning to disappear.

Even if government cuts do not deepen, which is unlikely, the Ernst & Young report claimed that a gap of $22.5bn on investment in renewable energy and subsidies is likely to emerge across 10 leading world economies in less than four years. Among them is the UK where the shortfall is estimated to be $5bn, while in Spain – effectively confirming Kistner's fears – it would be $6bn.

The Ernst and Young report came out in November, and reflects a growing concern about the ability to find the financing required to continue construction of wind and solar farms, even as the fossil fuel plants are being closed. European finances are in a difficult phase for other reasons, but in addressing rather large problems elsewhere, the funding and subsidies for renewable energy are likely to be reduced. The problems of a growing gap between the power that will be required in the future and that which will be available are so far being glossed over, but that is not an issue that can be hidden forever.

The arguments over the need for reducing the production of carbon dioxide continue to prevail in the mainstream. However, much as there was a change from Anthropogenic Global Warming to Climate Change, when the planet didn’t take the hint and follow the predicted model temperatures (even when assisted with a little judicious “adjustment” of recent trends, as the individual state temperature study revealed) so now there is the beginning of a move to change the concern from Climate Change to the increase in Extreme Climate Events induced by the changes in the atmospheric composition.

This allows those who wish to gut the current methods of energy production to make claims that any extreme event (including those where there is a lower than normal temperature) can all be laid at the feet of fossil energy production. This argument fails to consider that the study of events, such as cyclones, hurricanes and tornadoes have been going on for decades. Professor Curry implies that Kevin Trenberth was the initiator and instigator of this change in focus, and NOAA wants to allocate “the blame.” (Which sort of implies that before we had a power grid that perhaps we didn’t have extreme events.) Naturally the role that atmospheric compositional changes has in influencing these events will be evaluated by theoretical models – and naturally that will require more funding for bigger and better computers and more time build and run the models and to address the issues that arise . . .

The problem with establishing an industry built around modeling climate change and its effects is that in order to justify next year’s budget new ideas have to be advanced each year in order to keep those government dollars running and after a while it becomes harder to find those new concepts. The role of attribution of extreme events seems to be one of those newly developing tangents.

After a while the need for justification requires that somewhat wilder claims will be made, and while the main stream press is remarkably supine in accepting the statements made in published papers, there are times where credulity is challenged (on both sides). A relatively rare look at the truth of conflicting claims in two opposing op-eds appeared in the Houston Chronicle recently. The two pieces that were reviewed were an op-ed in Salon which lauded the arguments that extreme events are getting worse, all due to climate change. The review compared this with an editorial in the Colorado Springs Gazette which suggested that the Global Warming theories were losing their credence.

The first article had eight statements of fact which were:

By my reckoning, the strong evidence scorecard is 2 correct, 2 mostly right, 1 mostly wrong, and 3 wrong. I think this means that the author is able to type with one eye closed and his finger stuck in one ear. It’s difficult to argue that climate change is not a hoax when half of your debating points are the equivalent of hoaxes.

On the other hand, by putting up a plot of recent temperature trends he undercut the argument of the writer in the Gazette with no further criticism needed.

Which I suppose brings me to my ending gripe for this post. Those who are concerned over global levels of carbon dioxide have been every effective in selling the message that if you disagree with them, then you are saying that global warming is not happening. You are therefore a denier, and, by association with those who denied the Holocaust, you are an idiot.

One of the consequences of the Hockey Stick graph that Michael Mann has partially built a career on was that it denied the presence of the Little Ice Age. He has since, grudgingly, changed his mind and admitted its existence, but the recognition that the globe has been warming since the depths of the LIA has been neglected. Explanations for that warming trend have to be provided and the relative proportions of natural and anthropogenic warming properly evaluated before a truly valid discussion can be had over the role of the atmospheric composition, as opposed to the solar variations, on our climate. Just saying that the only thing that explains the change is rising CO2 becomes less persuasive as global temperatures fail to follow the predictions that, for example, Dr Hansen made in starting the whole shebang.

But those discussions are not held. With the imposition of the assumption that carbon dioxide is driving global climate change and forcing weather events to be increasingly extreme the goal posts are moved so that we do not discuss the weakness of the underlying argument.

The global financial changes are going to force governments to face more squarely the relative costs of their commitments to reducing carbon emissions. As they do so, they will need to justify backtracking from some of their earlier promises. At such time, while theoretical scientists demand more money their programs, justification and validation will be under increasing scrutiny and competition for funds may change the playing field. In future years it may be said that the high water marks of the climate movement were either just before the Copenhagen summit, or with the passage of the recent agreement in Durban. From here it may be increasingly downhill.

OGPSS - Some thoughts at the end of the year

2011-12-28T12:07:00.005-06:00

For most of this past year these posts have reviewed, and then discussed data on the state of different reservoirs of oil and gas that ultimately provide the power that we need and use every day. However, as we come to the end of 2011, it seems as though there is a gloss, or spin, being applied to stories about the state of global energy supply, which implies that concerns about future energy supply are overstated. Instead the impression is left that there will be, in the immediately foreseeable future, no return to shortages. So this post will be a more general view of the topic, less concerned with absolute numbers and references but rather seeking to suggest that these perceived words of wisdom are, like the promises of a return to $30 oil that we heard only three or so years ago, likely to fade into oblivion once they have served their immediate purpose.

It should be noted up front that there are considerable differences between the supplies of natural gas that are becoming available, and those of crude oil. Natural gas reserves are still increasing, I wrote just recently of the realization that exists in Azerbaijan that the gas being produced from the Shah Deniz field will have a hard time competing in the global market-place in three years, because of the arrival of natural gas from the Levant Basin. The relatively low prices for natural gas in the United States brought about by the development of wells in the gas shales, such as the Barnett, Haynesville and Marcellus and their initial high productivity will continue to make it difficult to see much increase in price. Yet this is at a time when the price that the natural gas is being sold for in America is around $3.50 per thousand cubic feet (kcf) ($124 per thousand cubic meters (kcm)). That price is often insufficient to totally cover the costs of its production and return a profit to all the investors, with some indications that such a price would need to be closer to $6.00 per kcf. The low price of natural gas however, relative to world prices, means that it helps to keep American industry competitive, since fuel costs are usually significantly lower here than elsewhere.

China continues to show foresight in acquiring fuel, since their agreement with and the creation of the pipeline from Turkmenistan now gives them natural gas at a competitive price ($280 per kcm - $7.93 per kcf) relative to the $400+ per kcm that Russia is charging Western Europe, though that price too will be vulnerable to supplies made available as the Mediterranean fields come on line.

The bent of the stories that have recently appeared seem to imply that the United States is moving toward significantly greater crude oil production, and thus a greater independence from foreign suppliers than will actually be the case. Folks such as Dr Yergin are projecting production of oil from the shales around the country as rising to some 2.9 mbd by 2020 and being sustained through time – neither of which is likely since the Bakken in North Dakota may well start declining and be significantly below 600 kbd within four years, and the likelihood of new developments bringing in more than this on a sustained basis are not great.

The emphasis on such a possibility, however, removes some of the pressure and concern in the short term over the health of the global supply situation, and the concurrent dependence of the United States on foreign fields and suppliers. One need not be (as perhaps the argument goes) so worried about the time to bring Libyan production back to 1.6 mbd. Optimistic reports talk of Libya reaching 1 mbd, yet still leave a concern that without a stable government and infrastructure that it will be a little difficult to reach those earlier production levels. And the promises that Iraqi production will rise to levels far above 3 mbd may be more dependant on political stability in a country that at the moment isn’t showing much. Any thought that the Arab Spring would bring swift changes in the governance of the countries involved, and leave oil exports to the world sustained at previous levels appear also to be less than realistic as countries such as Egypt begin to head into the second cycle of that revolution. The Syrian government is currently blocked from exporting (and thus producing) a third of their normal levels, which has taken 100 kbd or so from the market, and the situation with Iran continues to fluctuate.

Now there are some political benefits to being able to project that the world is going to have more than sufficient oil for the next few years, among them it distracts from the less than totally healthy state of the alternate fuels and energy industry. Exxon noted in their recent annual report that they see little significant impact from solar and wind energy on the overall global supply of power over the next forty years. Were the nation still fixated on where we were going to get our power over the next decade, then the collapse of Solyndra due to poor market support, and the bankruptcy of Range Fuels, because they could not produce cellulosic ethanol at the scale needed to have any impact at all, would raise worrying questions as to how we are planning to cope with shortage. The current optimistic state of mind, of course, also makes it less of an imperative to approve the Keystone pipeline, which may now not be approved.

Because of this lack of concern we see the Administration moving ahead to restrict further the use of coal fired power stations, through EPA enforcement of tougher emissions standards, the corn ethanol subsidies appear to be very rapidly on the way out, which may impact the volumes of ethanol (now over 900 kbd) that comes to the market in the future. But if the United States has become a net exporter of fuel, though mainly diesel, why should we worry? Perhaps it might be because that is such a small fraction of the overall total that it is really insignificant, even though it makes a nice headline.

The overall picture of crude oil supply to the United States, in reality, has hardly changed at all. Yes, demand for gasoline is down as cars are being driven less these days, and fuel economy changes have some small effect, but the economy is not robust (nor is that of Western Europe) and sustained high fuel prices are not going to help with recovery. At the same time demand in Asia continues to increase, and more nations in the Middle East and elsewhere are shipping oil to China in agreements that will still be in place were the United States to continue to recover and suddenly need additional oil to sustain that recovery of growth.

Current complacency and spin will not make those agreements go away, nor – by magic –will additional oil appear to assuage American demand. The only question that I have is whether the current spin can be maintained through 2012. It is certainly unsustainable through to 2014, and what impact the realization of reality might have, were it to become obvious by say September of this year, as the election enters its final phase is an ongoing puzzle.

We live in interesting times indeed, and I hope that you all have a Prosperous and Happy Year, as we sail into that future, and I look forward to commenting on some of these issues as we move through those times.

On giving to the charities Heifer International and Smile Train

2011-12-26T20:25:00.010-06:00

This post is a little outside the usual frame, but arises from that little bump of curiosity that keeps me writing these posts.

Background - For Christmas this year the Advocate had asked that we donate to a couple of charities that he supports: the Heifer International operation and Smile Train. Both of these are nationally advertised operations that function at above the $120 million per year range, and have received considerable positive publicity. Since I found more answers to questions I hadn’t initially thought to ask in a brief look at both operations, I thought I would pass on what I found. It may bear a little on your choice of giving.

Heifer International provides a catalog from which you can select animals, from camels to fish fingerlings, that the organization will provide to individuals in poor areas of the world, providing them not only with additional nutrition but also a way of starting a small business, as an aid to breaking their cycle of poverty.

My curiosity arose initially because I wanted to find out if there was any particular piece of livestock that would give a higher rate of return on the investment than others. My thinking was, illustratively, that perhaps it would be better to donate to buy a water buffalo, rather than a heifer, because of the additional work that the animal would be able to carry out, as well as providing milk, manure, and ultimately dinner. I had some fun for about an hour trying to tease out different rates of return, a heifer in Malawi could generate up to $130/month in milk revenues - helping to feed the family, while selling some milk, generated $60 a month in Uganda. On the other hand water buffalo in the Philippines would quadruple farm production, but still only up to $42 a month. Pigs could generate $45 a month (but how many?) and two alpaca will create 4 lb of wool a year at maybe $6 a lb, or just $2 a month – they must have other benefits. While the actual benefits weren’t always clear, as I poked through, my original choice of livestock didn’t look too bad until I came to a disconcerting post which pointed out that my research had actually been time wasted.

For the post pointed out that, had I bothered to read it, that this is what it said, at the bottom of the donation page.

To help the most number of families move toward self-reliance, Heifer does not use its limited resources to track gift animals from donation to distribution. Gifts made through this catalog represent a gift to the entire mission. We use your gifts where they can do the most good by pooling them with the gifts of others to help transform entire communities.

I must confess that, when making the donation I did not bother to read that small print at the bottom of the page, which may have now been changed to

The prices in this catalog represent the complete livestock gift of a quality animal, technical assistance and training. Each purchase is symbolic and represents a contribution to the entire mission of Heifer International. Donations will be used where needed most to help struggling people.

Now it is understandable that tracking individual gifts may be difficult and expensive, and I really did not expect that I would hear that a particular family had received the buffalo (see this video of what might be done), but I had hoped that someone (and in my imagination it was in Nepal) would get a buffalo, and now I was left wondering about the funding and where it actually might be going. There are, it turns out, other beneficial things that are being done with the money apart from the mission that is most heavily advertised. They help start farmer organizations and work with the International Red Cross in bringing war widows and Untouchables into the Nepalese community.

I also found a note which describes the policy in more detail.

Heifer provides community groups with livestock if and only if they request it after training in community values and studying the available resources. If they submit a strategic plan showing how they will care for the animals, how having livestock will substantially increase their livelihoods, then and only then does Heifer provide support. And then we ask that they source animals locally and “pass on the gift” of offspring AND TRAINING to others. The farmers use manure as organic fertilizer to increase crop production, plant trees to preserve the environment, raise honeybees and worms for composting, and on and on.

The Charity raised some $133 million in contributions in the year ending June 30, 2008, with the outgoing CEO getting some $288,912 in compensation. The overall organization had a paid staff of some 332 at the time, and fund raising used about 14% of contributions. Apparently the charity has also built a “Global Village” down in Arkansas, that has received some criticism since it detracts from the overall mission. (I suspect we will be travelling to Arkansas in the none-too distant future.) It appears that the charity had some 928 active projects, in 54 countries in 2009. It was sufficiently worthy that the Bill and Melinda Gates Foundation gave it $42.5 million (and they are reputed to do a fairly thorough review before they give the money). In the current annual report support is stated as being given to 1,000 families, with typical project support lasting over five years. And in the latest report it also gives some of the information that I started out looking for:

The average income gain from the project is $3,808 in Albania (equal to the average per capita income). In Nepal it is $572 (against income of $427) and in Uganda it is $1,456 (against an average income of $490).

Looking at the relative return on investment for donors - in Albania the ROI (annual dollar income per dollar for livestock) is 9.46 for cows; 7.51 for goats and 10.6 for bees. In Nepal it is 3.7 for cows, 2.87 for buffalo, 1.79 for goats and 0.8 for pigs. In Uganda it is 2.6 for cows and bulls, 5.72 for dairy goats but 9.75 for meat goats, while pigs bring in 8.32 and fish return 11.22.

However as Heifer notes the income is not the only benefit. Firstly the recipient has to pass on one offspring to another recipient in order to sustain the program, but then the recipient also has a steady long-term increase in assets that come from the additional offspring that the original gift produces. Thus, in Malawi, 90 initial beneficiaries are expected to grow to 130 families by the end of 2012. And in Uganda 118 original gifts of heifers produced offspring that were handed on to a second wave of recipients, so that, to date, some 223 families have been assisted.

This does, however, resurrect the question over how many different gifts of livestock are made each year. Typical projects are of about five year duration, with the first year being one of instructing the recipient on how to care for the gift, and in preparing the “compound” (livestock must not be allowed to roam and graze, but are fed within this enclosure which helps with collection of manure for fertilizer). The second year is where the recipient receives the gift, and, depending on species, at the end of that year or during the next, the first recipient will initially raise and then pass on an offspring to a second beneficiary. (It is not clear if the process continues thereafter with that second recipient also having to pass the “first child” on in turn, so geometrically multiplying the benefits over time). There are two more years of monitoring to ensure that the health of the gift and the economic welfare of the recipient, and to integrate the individual into a community to better market the product. The initial recipient also keeps (or sells) any additional offspring. For example one of the success stories told in the 2006 report was of a disabled Chinese farmer who received an initial gift of 12 goats in 2002. By the time of the 2006 report the family had increased the herd size to 230 goats (as well as passing on the 12 gift goats to other farmers). It is this kind of growth, that leaves the farmer independent and successful, that is a major goal of the program.

Perhaps I can express my concern, however, better with another example. From 2005 to 2009 the Moutori Livestock Development Project in Burkina Faso provided 400 chickens and 80 roosters to 120 original families. If we take the donation cost of the chicks, say 120 times $20, then the livestock cost is $240. The overall project cost was, however, $148,644 (project 21-1203-70).

Put another way, the goal in 2005 was to give livestock to 1 million families over 10 years. That is some 100,000 a year, but since this includes pass-ons from the original recipients. Heifer International only supplies livestock to 50,000 families a year. If each donation is the equivalent of a heifer (though it may be three or four goats, or perhaps two water buffalo) then the initial livestock cost (as defined in the catalog, and that seems about right) is $500 per family. 50,000 times $500 is $25 million. (And that is making a generous assumption, since as shown with the chicken example, livestock costs may be a lot less). With the charity taking in more than $133 million a year, it does point out that the animal supply part of the program, the donations for which provide the vast majority of the income for the charity, sees less than 18% of the income. Now that is not to say that the rest of the activities of the charity are not worthwhile and necessary, but it is not quite the way I had thought my donation would go. Putting it in perspective, while I thought we were contributing a water buffalo, the actual livestock part of our donation was more likely to have been one of those chickens. Ah well, as was said about the Harding and Coolidge Administrations who had put a “chicken in every pot,” that is a step toward prosperity, but it is not "one giant leap for mankind."

Which brings me to the Smile Train. It is important here to distinguish this charity from Operation Smile which has basically the same goal of treating impoverished children born with cleft lips and palates, and has been around a little longer. The founder of Smile Train was apparently once involved with Operation Smile, and started this similar charity in 1999, though with a different approach to the problem. In contrast with Operation Smile which sends American surgeons abroad to carry out the surgery, a practice for which it has been criticized, Smile Train relies on training and funding local surgeons in best practices.

Number of surgeries performed with Smile Train Support (Smile Train Annual Report )

They report helping 100,000 children a year, working with local doctors to carry out the surgeries and providing information to them on up-to-date techniques to improve the procedure. They also report having distributed software to more than 38,800 medical professionals, and run conferences and encourage methods of communication that keep these individuals up to date on their subject.

In 2010 their income (including contributions in kind) was some $162,296,235. They spent some $110 million on program services and education, and around $22.5 million on fundraising, claiming only $1,187,089 for management and general costs. There should be a little caveat here. (One of the two niggles that I have with this charity). The co-founder and President, Brian Mullaney, was compensated to the tune of $678,058 in 2009. And the books showed that the assets of the charity increased by $28.5 million, to $135 million. It claims to be one of the fastest growing charities in America, and apart from the President’s pay, the size and rate of growth of these assets is the second item that is a bit of a concern. The reason goes back to a remark that the President, Brian Mullaney, made in 2008.

Mullaney estimates that Smile Train is close to reaching a historic break-even point: it will perform more operations each year than the number of children born each year in developing countries with cleft deformities. This means Smile Train may be well on its way to putting itself out of business. “That,” Mullaney says, “would be a dream.”

Unfortunately before one reaches that laudable point, the charity will reach another, when it “runs out” of doctors to train and reaches the capacity of the system to handle patients in a given year. At that point the charity may take in more money than it can effectively spend.

That is not to say that the charity is yet at that point, it has been noted that there is still a significant problem in India, for example, where over a million children need treatment, with 32,000 new cases a year. But it may be running out of “room to grow.” It has also been criticized in that the cost of the surgeries is often higher than the $250 which is used in the advertising . If the number of operations per year, for example, is 100,000 and the program services (treatment and training) cost is $85 million, then the cost per surgery is perhaps $850, doing simple division.

And yet nevertheless this seems a very worthwhile activity to support, though maybe it is getting a little too successful at fund-raising, which might cause it to add other programs and thus dilute its effectiveness on the original task in the years to come.

And so, a couple of closing thoughts.

First I am not, in itself, against programs that send American physicians abroad to help with medical problems in disadvantaged countries. My optometrist, Bud Falkenhein, has won national recognition for his work in this field, where he annually has led a group of optometrists to different parts of the world to help with eye problems. But that is slightly different from bringing in teams of surgeons that do operations under time pressure and then leave before any development problems have been dealt with.

Second, I am still glad that I honored the Advocate’s request and made the donations to two charities that seem to be a cut above the general mix; it is merely that I thought that the funds that I sent would have been more productive than they will likely turn out to be. There is, after all, somewhat of a difference between a chicken and a water buffalo, and between one operation and two. (And yes - because my great grandfather was a village plowman, a position of respect in the Scottish villages a century ago - I am just a bit disappointed that I could not help another individual gain that "step up" with the donation that we made).

P.S. I also recognize that there are other charities who allow one to donate animals. For example Episcopal Relief and Development has a "Gift for Life" program, where for just a little more money I could donate a plow with the ox to pull it. Perhaps I will look into that in a little more detail, and perhaps add another comment on a charity that I have, in the past, looked favorably on, but whose website is not available tonight.

Compliments of the Season to all

2011-12-23T23:09:00.003-06:00

Gentle Readers:
Family affairs have intervened in the past few days to delay some of the new posts that I had planned, and with the Christmas and then New Year celebrations coming up posting will be quite sparse for another week.

May I therefore take the opportunity of thanking you for visiting here, and wishing you all the Compliments of the Season, and that you each find Happiness and Prosperity as we move into the New Year.

The 2012 Exxon Mobil view of the future

2011-12-16T23:35:00.009-06:00

Each year the major oil companies publish their projections on fossil fuel supplies as they foresee them developing over future decades. Last year I reviewed those for BP; Exxon Mobil; and the projections from Shell. Exxon Mobil (EM) has just released their new set of projections. With this publication they have also stepped a little further into the future, looking to an end point in 2040, rather than the shorter 2030 time frame of last year’s report.

One of the immediately striking effects of the change in end date is the highlight on the growth of the global population. In last year’s document the global population was expected to reach 7.9 billion by 2030, now the projection is for the population to increase to nearly nine billion by 2040. We are at roughly 7 billion today, and the acceleration in the future growth rate of the population will make it more difficult to improve the average global lifestyle. This is particularly true when the locus of that growth is defined as coming largely from India and Africa.

Anticipated growth in population in various parts of the world (EM Outlook for Energy 2012)

More tellingly EM anticipates that the number of households will increase by 50% over the next 30 years, and with that growth comes the demand for electrical power. EM looks at both industrial and domestic energy demand growth, tying it in with this population growth, and expects that, while OECD GDP will more than double, it will do so with only a small amount of growth in energy demand, with the somewhat smaller growth in GDP in the rest of the world using a considerable amount more of the growth in energy demand that EM foresees. In countries such as China the increased demand for space and energy come as, with greater affluence, families will no longer remain crowded into multi-generational dwellings but will move more to single family occupancy.
(As an update and an illustration how two different folk can view the same document, you might find Gregor's post on the same topic of some interest).

Where the growth in demand will come from (EM Outlook for Energy 2012)

With the rising affluence of the developing countries, EM still continues to see continued improvements in energy efficiency lowering the overall average household demand for energy through the next three decades. It is an argument that I believe requires more justification than they provide. It is interesting, apropos my recent interest in Azerbaijan and Turkmenistan, that EM do not see much change in the fortunes of those who like around the Caspian Sea. It is perhaps a cynical, but realistic view of where that energy wealth will end up.

Change in domicile, and the energy demand for the average home (EM Outlook for Energy 2012)

The most important part of the Review however, since it deals with energy, is how EM decides where this future energy will come from. They see a large movement towards diesel in the transportation industry as hybrids and electric vehicles reduce gasoline demand, and increased fuel efficiency with lighter vehicles combine to stabilize the overall levels of gasoline required.

Change in the fuel mix needed for transportation.

Overall the amount of oil needed for transportation will continue to increase, overall by about 80%, and when this is combined with other needs, EM sees that global demand for oil will increase, by 2040 to around 110 mbd at a steady rate of increase overall from today, although the way in which the mix is put together is anticipated to change considerably. (And as an aside this projects less than a 1 mbd per year increase in demand, which falls below the levels which others, such as OPEC, foresee. OPEC anticipate a growth in demand of 1.1 mbd in 2012, according to the December MOMR).

Anticipated sources for oil through 2040 (EM Outlook for Energy 2012)

There are many features of interest in this summary chart. Given the decline rates that are now evident in conventional wells around the world, I do not see the discoveries being made that will justify the production levels that EM are predicting. The plot which is included, showing the production history from discoveries of different ages, is telling in this regard.

Production for well discoveries of a certain time (EM Outlook for Energy 2012)

EM notes that modern wells are more likely to be drilled with long laterals, rather than the simple vertical or slightly deviated wells of little more than a decade ago. But these new wells carry with them a much higher decline rate at the end of their lives than do the conventional wells (often more than double). Thus, as production declines from the older wells, so reliance must pass to new-found deposits, and that particular reserve is, as the above graph shows, somewhat thinner than volumes from the past, which are now starting to decline.

The savior of the next decades is foreseen to be the offshore Deepwater deposits, and certainly as one looks along the shores of Africa, South America and the Gulf of Mexico, to name but three, there is a considerable potential for some gain. Whether it will provide the sustained volumes needed to balance other declines and also produce enough to match increased demand is going to be a continuing question. With that in mind it is worth revisiting last year’s review to see where EM expect this Deepwater oil to come from.

Deepwater oil production (EM Outlook for Energy 2011)

As befitting an oil and gas company, perhaps, EM expects that oil production will remain a major part of the energy mix through 2040, with natural gas rising to carry an increasing burden of the overall picture at the expense of coal, and biomass whose shares of the global market are expected to decline starting somewhere about now.

Change in natural gas demand over the next 30 years. (EM Outlook for Energy 2012)

Composition of the fuel mix according to EM over the decades

Even though they project that coal will still be the cheapest fuel to buy and while solar will remain a luxury item, nevertheless EM anticipate that coal’s share of the electricity generating market will fall to less than 30% by 2040, and to less than 20% of the overall energy supply. This remains consistent with their opinions from last year. However they are now projecting a larger role for oil than they expected last year (when it was around 26% of total supply by 2030 and falling).

OGPSS - Looking at Azerbaijan future fuel production

2011-12-13T13:23:00.009-06:00

The President of SOCAR, the State Oil Company of Azerbaijan, is touring the United States at the moment. His goal is, in part, to gain support for the Baku Higher Petroleum School, a place to generate the indigenous engineers that his firm needs for future resource development. (About 75% of the labor force is currently Azeri, but at lower levels of management). The school is expected to open its doors next September. While this is, perhaps a little late to the game, it underscores the global need to find those individuals who can be technically trained and who are then willing to spend weeks of their lives, at a time, in increasingly remote parts of the world, often in inclement conditions, just so that the rest of us can have an easy commute to work in the mornings. (Folks were even talking about the opportunities in the wilds of North Dakota at our Rotary meeting this week).

The effort by SOCAR also underscores the point that there remains a future for the petroleum industry in Azerbaijan, despite the long history of oil recovery that the nation has already seen, with the depletion of many of the old reservoirs. There are new fields in which oil and natural gas are being developed, though as Darwinian pointed out, the rapid build-up in production to which I referred last time, has, more recently, begun tailing off. He referred to the Joint Organizations Data Initiative – Oil (JODI) which shows the decline from 1.05 mbd in July 2010 to 920 kbd this September. That peak was down from the peak of almost 1.1 mbd in early 2008. This year the decline has reached around 11% pa and while SOCAR explains that this is the result of introducing additional safety measures following the Deepwater Horizon event, and for scheduled maintenance, the number seems a little large for such a cause.

Further if one looks at the drilling record for the country, SOCAR reports that while drilling was down last month (and likely will also be this month) overall they anticipate exceeding the 2010 figures, with roughly 90% of the work going for development and about 10% for exploration. The development drilling is down from the 2010 figure, which was itself lower than that in 2009, which was below that of 2008. But some of this may have been market driven, one can certainly see that in the natural gas numbers that I discuss below.

I had missed, when I wrote the post last week, that Jerome had previously written on the topic in 2008, my apologies to him and you for that omission. His post gave more detail of the fields off the peninsula than I had provided, so I am reproducing a figure from the post here:

Oil and gas fields off Azerbaijan (Jerome at TOD)

The recent decline in overall oil production impacts flow through the pipeline from Baku to Ceyhan (the BTC pipeline) which had a targeted flow of over 1 mbd, and much of this comes from the Azeri-Chirag-Gunashi fields (there is some crude also from Turkmenistan, and condensate from Shah Deniz). IHS list it as currently the third largest oil field (behind Saudi Arabia’s Ghawar and Kuwait’s Burgan). Recent production from the complex can be obtained from the BP site:

During the first three quarters of 2011, ACG produced on average 757,500 barrels per day (b/d) (206.8 million barrels or 27.9 million tonnes in total) from the Chirag, Central Azeri, West Azeri, East Azeri and Deepwater Gunashli platforms.

At the end of the third quarter of 2011, a total of 57 oil wells were producing, while 27 wells were used for injection in the ACG field, as follows:

Chirag had 12 wells (8 oil producers and 4 water injectors), producing on average of 73,300 b/d.

Central Azeri (CA) had 19 wells (13 oil producers, 5 gas injectors and one water injector), producing on average 209,200 b/d.

West Azeri (WA) had 19 wells (13 oil producers and 6 water injectors), producing on average 213,800 b/d.

East Azeri (EA) had 14 wells (11 oil producers and 3 water injectors), producing on average 134,300 b/d.

Deep Water Gunashli (DWG) had 21 wells (12 oil producers and 9 water injectors), producing on average 126,900 b/d of oil.

Development of Chirag (EPC Engineer )

A new platform is in construction for Chirag, aimed at adding 185 kbd to current production in 2013, which with increased drilling at the other platforms (averaging about 20 wells a year) may, in the short term, bring the production back toward the 1 mbd target production. The total estimated recoverable reserve is estimated at 5.4 billion barrels of oil, of which around 1.8 billion is estimated to have been produced to date. The partnership is currently extended until 2024.

The natural gas picture is a little more complicated. Although the ACG complex produces more gas than Shah Deniz roughly 75% of it is re-injected to maintain reservoir pressure. Discounting the production from Shah Deniz, SOCAR is still producing natural gas for export to Europe, for which it is still being paid on average $191 per 1,000 cu m (kcm) ($5.40 per 1,000 cu.ft or million Btu approx) this year (though down to $151 in October). These prices are significantly higher than the $61 per kcm it received last year, and are also ahead of the $186 price in 2009, though just under the 2008 average.

They are undercutting the price of Russian gas, which they report as being some $446 per kcm this year, though it is anticipated to fall to $415 next year. (In perspective Ukraine is currently paying $400 per kcm, ($11.33 per kcf) for Russian gas, but hoping to get that price lowered).

SOCAR is anticipating that this market may dry up in three years when the gas fields off Cyprus are brought into production. This will be gas from the Aphrodite gas field, which holds some 3.3 Tcm of natural gas – about three times the reserves for Shah Deniz. That area of the Mediterranean is, however, quite politically sensitive.

Together with other fields (Leviathan and Tamar), this area of the Mediterranean is estimated to have 10 trillion cu m of gas. In connection with the worsening political and military situation fields Leviathan, Tamar and Block 12 have been patrolled by Israeli drones. Russia sends its only aircraft carrier to this area, while fleets of other countries claiming to develop these fields are drawing as well.

These new fields lie in the Levant Basin Province, and, given this location and the neighborhood, who will end up producing what is going to be an interesting development to watch. Given the size of the deposits, their development could also change the economics of natural gas distribution for some time.

Location of the Levant Basin Natural Gas Province (Fast Company )

SOCAR is hoping that, as this transpires, it may get additional supplies from Turkmenistan through a trans-Caspian pipeline that could be completed by 2015. Concurrently Shah Deniz II, slated to produce some 100 kbd of oil and 16 bcm of natural gas, is being prepared for production to start in 2017.

In short, in the short term production of oil from Azerbaijan will continue at roughly current levels, but the volumes of gas that will be available on the global market may exceed demand within the near future unless, as now, they significantly discount the price.

AMO, NAO and predicting Atlantic Coast temperatures

2011-12-12T00:27:00.010-06:00

Several months ago, after finishing the individual state temperature evaluations, I started putting the state data together in regional groups, starting with the Atlantic States. What motivated that start was the discovery that, along the East Coast, the individual states all displayed a drop in temperature, over the period from about 1950 to 1965 on the order of 4 degrees F. This was a surprisingly large number, in terms of the consistency over both space and time, with which the fall in temperature occurred. But there was some physical evidence of the impact of these changes since, following a piece on bird populations, it was possible to tie the fall in temperture to the migration of the Black Capped Chickadee, as an example, which moved south as the temperature fell, appearing for the first time in North Carolina at the height of the cold spell. When the average plot for all the states (excluding Florida) was derived the average fall was reduced to about 3 degrees F, with the drop in temperature reducing for states further South.

Averaged Time of Observation corrected (TOBS) temperatures for the Atlantic states, with state averages weighted by area in the overall average of the data.

Today’s post shows how this can now be explained, and how it might, from existing data, be possible to predict the future shape of this plot.

Looking at the range of states over which this fall occurred it was clear that it while the temperature drop made it across the Adirondacks into the Midwest it got no further and the Midwest had some differences in the pattern of temperature recovery. The weather normally travels from West to East, and so the logical cause seemed to be to look first at what happened in the Pacific, to see if US temperature variations could be explained.

Over the last couple of weeks this has taken the course of looking at the impact of the El Nino Southern Oscillation (ENSO) with its roughly 5-year cycle, first on regional temperatures and then on that of the individual states. While changes in the ENSO impacts moisture and drought patterns in the states, it did not, comparing temperatures, seem to have as great an impact on the temperatures along the West Coast, where the current flows impact. And further it was restricted to coastal states, in what correlation was immediately visible.

Coming back to the Atlantic Coast there is a similar oscillation in the sea surface temperatures (SST) called the Atlantic Multidecadal Oscillation (AMO). Looking at a plot of this average over time, it is immediately clear that there is a concurrent drop in these temperatures, in around the same time period, that might answer the question at to what had caused the temperature drop along the East Coast.

Sea Surface Temperatures in the Atlantic showing the AMO (NOAA )

One can then, in the same way as for the Pacific Coast States, overlay this curve on the average of the Atlantic States variation (with the Midwest added to show the limit of range) to validate the above statement. However in the first step the overlay was kept at the same vertical scale, so that the size of the anomaly in SST’s that forms the oscillation, could be compared with the size of the temperature changes on land.

Comparison of the fluctuation in AMO anomaly with the temperatures on the Atlantic and Midwest regions. Note that the AMO plot has been scaled and randomly placed vertically to allow distinction from the two other curves.

The immediate first observation is that the land temperatures have fluctuated over twice the scale (roughly) of the SST values, though it should be remembered that the latter are averaged over a much greater area.

Looking over the entire history of the temperature record, which for now is taken as post 1895, the plot for AMO values is doubled, to make it easier to see how the peaks and troughs may coincide, and then 52 deg F as added to the anomaly values to set them below the Atlantic States, and the values are averaged for each year.

Comparison of the form of the AMO (which has been doubled in size) with the changes in the average temperatures of the Atlantic States over the past 112 years.

So now the question comes as to the cause of the changes in the AMO, and one finds that this is currently a work in progress. The AMO itself was only described in 1994, and work on what is the cause, and what it correlates to is ongoing. But there are are several different other cycles in the Atlantic, and it is interesting to see what folk have already found by way of correlation.

One of these other cycles is the drift of the InterTropical Convergence Zone, or ITCZ. Back when I was reading “Stories for Boys” about sailing ships in the Atlantic the ITCZ was called the “Doldrums.”

Location and characteristics of the ITCZ (Da Silva 1994 ).

The Doldrums drift North in the summer. However the movement and nature of the ITCZ behavior has been suggested to be dependent on the AMO, rather than the cause (see for example Knight, Folland and Scaife)

What is actually more interesting, particularly from the “climate prophet” point of view is a suggested correlation with another Atlantic Cycle, that of the North Atlantic Oscillation.

North Atlantic Oscillation – NAO is defined as the fluctuation in the difference of atmospheric pressure at the sea level between two specific locations: Ponta Delgada, Azores and Stykkisholmur/Reykjavik.

Although the NAO is now undergoing a name change to the Northern Annular Mode, the relevant changes in atmospheric pressure (which are shown in color and globally at the Climate Prediction Center can be illustrated, to allow easier layman comprehension with this picture from JISAO).

Pressure patterns in the North Atlantic showing the pressure difference that builds up to value the NOA. (JISAO via Gosselin)

Comes now this new paper from Vukcevic which suggests that there is a correlation between the AMO and the NAO, but that the correlation becomes much better if the values for the NAO are delayed by eleven years. Further that the correlation becomes better when only the fluctuations in the pressures at Reykjavik are considered.

Correlation between an eleven year lagged Icelandic pressure and the 3 year moving average SSTs in the Atlantic – the AMO. (Vukcevic )

What is riveting about this is the current correlation not only the AMO and NAO, but that it is time lagged. And as Vukcevic notes, there is an eleven year time lag between the behavior of parts of the NAO and the consequent change in the AMO. Which means, if this is correct, then we know what the future behavior of the AMO is going to be, since the end of the red line above indicates the SST trends over the next eleven years. That in turn, as was shown earlier, means that the temperature trends for the Atlantic Coast can also be surmised for the next eleven years, and as has been noted elsewhere this holds true not only for the United States but also Europe in that the NAO also has been shown to influence the Central English Temperature (CET).

This is obviously quite intriguing and will no doubt be the object of some discussion over the next few months, particularly since a second paper is promised. It is unlikely that it is the drop in pressure itself that is the cause, but it is conceivable that this is an indicator (dare one say proxy) for some other event and as such it is indicating how this other forcing event is behaving, and through that route becomes a marker itself for the temperature changes that are coming. But then that raises the question as to what it is a proxy for?

ONI and individual state temperatures

2011-12-08T22:49:00.009-06:00

The influence that sea surface temperatures have on land temperatures and climate is an ongoing debate, and I mentioned this somewhat in my last post on this topic. However, in looking back over that post it was perhaps too general an approach to look at the impact of the El Niño events over the large scale of the West Coast, and thereon East. Given that effects were, as I showed, more regionalized and remembering that we are in a La Nina winter, I’ll just repeat the anticipated effect plot from Kumar, et al.

Impacts of a La Nina winter (after Kumar et al).

The disadvantage of using the regional average can be seen just in the US West Coast. At the upper end the season is cooler and wetter, while down in the south it is drier and warmer – the average might well be “no change.” So since we have the individual state temperatures for the period I looked at last time, I thought it might be interesting, before looking at other Oscillations, to just check how this event correlated on a more localized basis.

The ONI plot from 1950 (GGWeather )

It is logical to start on the West Coast, and given that the predicted impact this winter will be on the upper Northwest, the first comparison is with Washington State. For now I am going to use the homogenized data set, rather than the TOBS data, though I may come back later to look at how that changes things. (This is the fun of doing this without an agenda, we don’t need to have the data fit any pattern, so it is more informative to look at options).

The ONI plot overlain on a plot of Washington state temperatures.

It can be seen that while there was some correlation, in places, overall the agreement is not very good.

The other states that seem to be most impacted are the southern tier, that would include California, Arizona, and possibly New Mexico and Texas . From the regional comparison the Pacific SST effects seem to weaken somewhat once one gets over the Rockies, hence the caution as to how far we might expect the impact along the South Coast – so we shall see.

Turning first to California, recognize in the beginning that with the state being as long as it is, there are internal temperature variations along the state, Overlaying the ONI plot on the relevant part of the California temperature curve:

Relation of California temperatures to ONI temperature anomalies

My sense is that the correlation is a bit better, but still lacking. So let’s try the Arizona comparison:

Relation of Arizona temperatures to ONI temperature anomalies.

There does seem to be more of a correlation here, than with the earlier comparisons.

Moving on to New Mexico, and the same superimposition:

Relation of New Mexico temperatures to ONI

Well what correlation there was in the first states seems to be getting less here, lets try Texas.

Relation of Texas temperatures to ONI

Well, using that well known calibrated eyeball, it would appear that the correlation seems to get worse as one moves away from the Pacific.

Well this wasn’t totally what I was expecting, though I mentioned at the top that I suspected that the effect might not reach as far as New Mexico. so I think I will cogitate a little more on this before venturing an opinion. However it might be worth looking at relative precipitation levels, since this seems to be more the effect that is most obvious. (Though that also gets into cloud formation . . . . . . )

Still watching Katla

2011-12-08T12:10:00.007-06:00

It has been a little while since I wrote about the possible eruption of the Katla volcano in Iceland. For a while it appeared that the increased frequency of earthquakes and their growing magnitude, was leading toward an eruption. Since then the mountain has become somewhat quieter; but the earthquakes remain focused around the caldera, and continue to occur at a higher than background rate. Looking at the pattern over the past 24-hours, there is still a strong linear component to the earthquake pattern, which would tie in the continue evolution of fissures along the edge of the caldera.

Earthquakes around Katla in 24-hours (Icelandic Met Office ).
UPDATED

Jón Frímann does not expect this activity to lead to an imminent eruption, nor do I. But the continued linear nature and focused activity around the caldera is indicative of an ongoing preparation for an eruption. However we are talking about geological events, where time has a somewhat different meaning. Imminence is more likely therefore to be months, rather than days. Yet, as Jon notes, normally winter is a period of quiescence and this year we have not seen that. So I continue to expect an eruption of some significant size, it is just not clear when.

UPDATE
Revisiting the site a day later, there is still a lot of ongoing focused activity, though not yet strong enough to show any immediate large scale activity.

OGPSS - an initial look at Baku and Azerbaijan

2011-12-02T16:34:00.010-06:00

“The Prize”, itself a prize-winning history of oil written by Daniel Yergin covers the growth of the oil industry around the world, and begins with the start of the industry in the United States. But right behind those early chapters comes the story of Russian oil. This is not surprising since between 1898 and 1901 Russia and America roughly split global production of around 500,000 bd between them, with Russia out-producing the United States on occasion (as it does again now). That Russian oil is Russian no longer, since the early oilfields were found on and off the Aspheron Peninsula in what is now Azerbaijan. (It was annexed by Russia initially in 1813 by Alexander 1). The first well was drilled in 1847, after decades of recovering the oil from hand-dug pits, and there has been ongoing activity there ever since. By 1904 the Baku region was producing 73 million barrels a year, although production began to decline after that. And with the loss of much of its male population with the revolution, it took a long time to recover. Yet it had rebounded to be strong enough that this oil from the Baku reservoirs was considered a critical factor in governing many battles of the Eastern Front in Second World War.

Azerbaijan sits in a region of states that run along the southern Russian border, and which hold the promise of holding some of the last large deposits of fossil fuel that have yet to be fully developed.

Location of Baku, and Azerbaijan (Google Earth)

The first fields to be developed were the onshore Balakhany, Sabunchi and Ramany in 1871 with the coastal field of Bibi-Eybat being developed in 1873. Such was the nature of prospecting at the time, and the multiplicity of oil-bearing layers in the ground that oil still remains to be found and recovered. It has been estimated that the fields initially held around 8 billion barrels of oil (John Grace) but that while a billion of this was within range of early technology, the rest waited for the more advanced western technologies to arrive, and sometimes it didn’t.

As a result, within the last year, new wells have been sunk in these old fields. One at Balakhany is aimed to be 3,200 ft deep, with a target production of 28 barrels a day, Most of the production was produced following the Russian Civil War and in the lead into World War 2. In 1913 production was at 206 kbd, but fell to 81 kbd by 1921, and then slowly built until the region was producing 622 kbd by the start of WW2.

Balakhany today (Alexander Zaitchik )

The older fields no longer have the reserves to justify the investment of the large capital equipment associated with modern technology, but their history describes the wealth that they produced before the first World War, first for the Nobel family, and then for the Rothschilds. Baku oil also underwrote the career of Mr “Five Percent” Calouste Gulbenkian. Daniel Yergin notes that it was the need to replace expensive British coal that led Russia to use oil first in ship bunkers on the Black Sea, and then to fuel the railway engines across Russia. However production continued to fall from the original wells at Baku, Royal Dutch/Shell had bought out the Rothschilds, yet in the period just before WW1 Russia’s export market share had dropped below 10% as the shallow fields ran out. Of course this was also the time that Stalin was learning his trade as an organizer/agitator in the Baku fields., though it was not until 1920 that the Bolsheviks took Baku and nationalized the oil industry.

Azerbaijan remains, however, with the fields off the peninsula, the source of a growing percentage of global production. Because of that it is where the Baku-Tiblisi-Ceyhan pipeline begins. The BTC pipeline carries up to 1.2 mbd of oil to the Turkish port of Ceyhan on the Mediterranean where it can be loaded into tankers.

Path of the BTC pipeline (Central Asia-Caucasus Institute)

To meet this, and other demands the re-growth of the oil industry in Azerbaijan has, within the last decade, raised production from 283 kbd to more than 1 million bd.

The most productive of these fields lies 62 miles east of Baku, in the Caspian, where the complex of fields known as the Azeri-Chirag-Gunashli (ACG) field lies. The complex is believed to hold 9 billion barrels of oil, though these are only a few of the fields found in the region. Yet there is a world of difference between how these fields are being developed with modern equipment and investment and the fate of the older fields.

The oilfields of Azerbaijan (Offshore Technology )

It is here also that the Shah Deniz field, with 22 Tcm of natural gas and 750 mb of oil can be found.

The region has thus not only had, but continues to have significant fossil fuel reserves. Production this year averaged 989 kbd to date, with $19 billion in exports of 715 kbd. This is up from last year, but down from the 2009 figures.

As the volume of oil available has increased, so the market for Azeri oil has also grown. Azerbaijan began exporting oil to India this year, and already sends some to China. It plans on sending oil to Czech and Ukrainian refineries and to Slovakia, to the tune of around 15 million barrels a year. The diversion of more to countries of the Former Soviet Union is something that has caught OPEC attention, and they note, in their November MOMR that the booming Russian economy is increasing internal demand, with a consequent cost to exports, to the tune of around 100 kbd growth in demand in the FSU to 4.2 mbd.

FSU oil demand change (y-o-y) in kbd for selected countries (OPEC November MOMR )

In terms of natural gas production the IEA projects that this will grow from a current 17 billion cubic meters (bcm) a year to 50 bcm by 2035, much of this to come from the second phase of the development of Shah Deniz.

In this regard it should be remembered that there are three main oil pipelines that carry oil out of Azerbaijan and while the BTC carries the majority, the Baku-Novorossiysk pipeline (B-N) carries 7% of the exports to the Black Sea Russian port of Novorossiysk , and the Baku-Supsa pipeline carries 14% of the total feeding oil to the Georgian port of Supsa, with a capacity of 145 kbd. The flows from Azerbaijan to Russia, via the B-N pipeline have been fluctuating all year, but on average have fallen over 12% from last year.

Average monthly flow in the pipe from Azerbaijan to Russia (News.AZ )

It may be that, in the same way that Russia used to play with demand for gas from Turkmenistan, they are now playing the same game of cutting back demand in order to force lower prices. However as with the Chinese pipeline to Turkmenistan, the BTC pipeline from Baku provides other customers so that prices may now be maintained – and with them support for the local governments. (The Azerbaijan government now has a strategic reserve of $41 billion).

Climategate 2, more unethical Team behavior

2011-11-28T13:42:00.007-06:00

The second batch of e-mails, (Climategate 2)(you have to register) documenting the “behind the scenes” activities of the scientists that have been some of the stronger advocates for the uniqueness of current global warming over the last two millennia have been released. They have now been perused in running series of posts at various blog sites, and, while there is no immediately obvious major new revelation, the contemptible behavior of these purportedly exemplary individuals is getting an increasing amount of sunlight. It also shows how thick the whitewash was in the “enquiries” into scientific misconduct that followed the release of the original, Climategate 1, e-mails.

As an example, New Zealand Climate Change has shown in two posts ( here and here) how “reputable” scientists (Phil Jones, Michael Mann, Jim Salinger, Tom Wigley, Barrie Pittock, Mike Hulme and others – i.e. "the Team") worked to get Chris de Freitas, then editor of the journal Climate Research fired from that position, and also worked to try and get him fired from his academic position. His “crime” was to allow, following peer review, a paper that challenged the validity of the initial Mann “hockey stick” paper and its conclusions that the late 20th century was the warmest of the last millennium. (That particular conclusion was later changed, by Dr Mann, though much later than these events).

To explain the heinous nature of this particular activity requires some background, and also some information that has only since emerged. And, for the sake of brevity I am only going to summarize the story, though adding some detail not in the NZ post.
At the beginning of the story, back in 1997, the state of historical climate science thinking was that between AD 900 and AD 1300 (roughly) the world was going through a warming period, roughly akin to that we are currently seeing, and known as the Medieval Warming Period (MWP). This was followed by a much colder period that lasted from AD 1400 to AD 1800, known as the Little Ice Age (LIA). Evidence for this can, for example, be found in a study that was carried out looking at the sediments laid down in lakes in Finland. In 2005 Mia Tiljander submitted her thesis on these sediments in which she found, in concurrence with earlier studies of sediments in other lakes in the region that:

During the Roman period there was in AD 140-220 an 80-year-long period in the Lake Korttajärvi area when organic matter deposition and the sedimentation was similar to that during the Medieval Warm Period (MWP), interpreted as milder climate condition. After this period, a clear mineral matter – organic matter varve structure existed, until the beginning of the MWP.

The MWP, AD 980-1250, was an exceptional period. The MWP is characterized by thinly laminated varves rich in organic matter, almost lacking the mineral pulses (i.e. spring floods), indicating mild climatic conditions. This period was interrupted by a colder period from AD 1115- 1145, dominated by mineral-matter-rich varves. The sediment deposited during the MWP was highly organic and dark brownish in colour. Based on pollen and diatom studies (Kauppila 2002), the MWP was a two-stage event. AD 980-1100 was warm and dry, a cold spell (AD 1115-1145) interrupted the warm trend and the following period AD 1145-1220 was again warm and even drier than the first stage.

In light of subsequent discussion of her work (which comes later) it should be noted that the disturbance of the annual sediment layers (the varves) by human activity only occurred in sediments after AD 1720, i.e. towards the end of the LIA. The picture of the historic climate can thus be outlined, as it was understood, by a plot from the first IPCC report.

Global Temperature plot from the first IPCC report (IPCC via John Daly )

This picture was challenged with the publication by Michael Mann, Raymond Bradley and Malcolm Hughes of a paper in Nature in 1998 (MBH 1998) that introduced the “Hockey Stick” plot to the world. Contrary to the prevailing opinion this paper suggested that there was a steady decline in temperatures from 1000 AD to around 1850 AD (the handle of the hockey stick), following which temperatures rose steadily to their present high levels (the blade).

The original “Hockey Stick” from MBH 1998 (MBH via John Daly ) (Note the thickness of the green error bars).

This plot made it easier to argue that current temperatures were a direct cause of industrial activity, due to the generation of increasing levels of carbon dioxide as the world used more fossil fuel. And, as a result, MBH concluded:

Our results suggest that the latter 20th century is anomalous in the context of at least the past millennium. The 1990's was the warmest decade, and 1998 the warmest year, at moderately high levels of confidence.

This conclusion and the elimination of the MWP and LIA, despite the fact that the curve and conclusion over-rode the combined papers of hundreds of scientists who had worked to validate their existence, was seized upon by the Global Warming community and used without further discussion, as the “New Bible.” It was, for example, prominently featured in the 2000 Third Assessment Report of the IPCC. I have seen it used by the current Secretary of Energy as the valid plot of temperatures over the past millennium and thus as justification for the programs he espouses. And this despite the torrent of valid criticism of the curve, and that the original plot only referred to the Northern Hemisphere.

To sustain the credibility of this plot, the warming of the MWP, and the cooling of the LIA, had to be minimized. Both the initial set of e-mails and the new set document that the Team recognized and worked to do this. One immediate challenge was to respond to a paper published in 2003 in the journal Climate Research by Willie Soon and Sallie Baliunas which had looked at some of the previous data (which MBH 1998 had neither considered nor shown invalid) to conclude that:

Furthermore, the individual proxies can be used to address the question of whether the 20th century is the warmest of the 2nd millennium locally. Across the world, many records reveal that the 20th century is probably not the warmest nor a uniquely extreme climatic period of the last millennium.

Such effrontery and direct challenge to the authority of the team could not go unanswered, and the Team swung into action, (e-mail 31 ). It is interesting to note that in that correspondence Phil Jones recognizes the work of Jean Grove, an early climate scientist, (who reviewed the data validating the presence of The Little Ice Age in an excellent seminal book), but who died in 2001).

What we want to write is NOT the scholarly review a la Jean Grove (bless her soul) that just reviews but doesn't come to anything firm. We want a critical review that enables agendas to be set.

Which was not how I remembered the text at all, and so I re-read the beginning of that book, and it shows that he was wrong in that statement. Dr. Grove wrote:

Historical evidence of Little Ice Age events is much more plentiful in Europe than elsewhere but the documentation from other continents though scantier, is supported by a great volume of field evidence (e.g. Hope et al 1976, Hastenrath 1984) which is presented in Chapters 7, 8 and 9. It emerges that the Little Ice Age was a global phenomenon and it is shown in Chapter 10 that it was not unique to the Holocene.

But it was not just enough to write a rebuttal paper (which would be normal scientific practice). Although a rebuttal paper was written, with Tom Crowley suggesting that it be in EOS, this was not considered sufficient. Beginning with an e-mail from Mike Hulme (e-mail 2272) ) the Team began to focus on the editor, Chris de Freitas, who had accepted the paper.

Whilst we do not know who reviewed the Soon/Baliunas manuscript, there is sufficient evidence in my view to justify a "loss of confidence" in the peer review process operated by the journal and hence a mass resignation of review editors may be warranted. This is by no means a one-off - I could do the analysis of de Freitas's manuscripts if need be.

I am contacting the seven of you since I know you well and believe you may also have similar concerns to me about the quality of climate change science and how that science is communicated to the public. I would be interested in your views on this course of action - which was suggested in the first place my me, once I knew the strength of feeling amongst people like Phil Jones, Keith Briffa, Mike Mann, Ray Bradley, Tom Crowley, etc. CSIRO and Tyndall communication managers would then think that a mass resignation would draw attention to the way such poor science gets into mainstream journals.

Pressure was brought to bear, initially forcing changes in the editorial practices at the Climate Research journal, and then leading to the resignations of the editor in Chief (Hans von Storch) as well the one who accepted the paper (Chris de Freitas), and two others (Clare Goodess – who was at the University of East Anglia with the CRU group and Mitsuru Ando) who protested the publication, and who were encouraged to resign by the Team (e-mail 4808). It led to an editorial by the publisher, explaining why they could not allow the publication of papers in the journal to be governed by individuals outside the peer-review process (i.e. Team members).

The lack of objectivity of the editors of the journals in which the Team publish(such as Science, for example) is shown by theTeam being solicited by the journals to write opposing articles for them, as a counter to the Soon/Balianas paper. (e-mail 2469).

Phil Jones and I are in the process of writing a review article for Reviews of Geophysics which will, among other things, dispel the most severe of the myths that some of these folks are perpetuating regarding past climate change in past centuries. My understanding is that Ray Bradley, Malcolm Hughes, and Henry Diaz are working, independently, on a solicited piece for Science on the "Medieval Warm Period".

Of course, since then, Mann among others, has admitted to the presence of an MWP and an LIA, but it is a little late . . .

The Team were still not satisfied, and as the New Zealand post points out, they suggested that a letter be sent to the head of the University at which Dr de Freitas works, (e-mail 3052)

I have had thoughts also on a further course of action. The present Vice Chancellor of the University of Auckland, Professor John Hood (comes from an engineering background) is very concerned that Auckland should be seen as New Zealand's premier research university, and one with an excellent reputation internationally. He is concerned to the extent that he is monitoring the performance of ALL his senior staff, from Associate Professor upwards, including interviews with them. My suggestion is that a band of you review editors write directly to Professor Hood with your concerns. In it you should point out that you are all globally recognized top climate scientist. It is best that such a letter come from outside NZ and is signed by more than one person.

The e-mail goes on to suggest the form of the letter that should be sent:

Instead we have discovered that this person has been using his position to promote ‘fringe’ views of various groups with which they are associated around the world. It perhaps would have been less disturbing if the ‘science’ that was being passed through the system was sound. However, a recent incident has alerted us to the fact that poorly constructed and uncritical work has been allowed to enter the pages of the journal.

A recent example has caused outrage amongst leading climate scientists around the world and has resulted in the journal dismissing (??).. from the editorial board. We bring this to your attention since we consider it brings the name of your university and New Zealand into some disrepute. We leave it to your discretion what use you make of this information.

The strength of the punishment that the Team inflicted on the journal and those associated with the story kept the peer reviewed papers “in line” for some time, and so it has only this last September (after some 8 years) that it has been necessary to force the resignation of another editor, Wolfgang Wagner, to remind the scientific press as to who is in charge here.

Let me, however, end this rather lengthy post with another piece of Team dishonesty. You may remember that I began by quoting Mia Tiljander’s work on Finnish lake sediments. Well due to an odd circumstance, when this was examined by the Team the results were inverted. As a result, instead of showing the MWP that actually existed, her results were included as showing that it did not.

This was admitted in the first Climategate release (e-mail 3511) where Darrell Kaufman wrote

Regarding the "upside down man", as Nick's plot shows, when flipped, the Korttajarvi series has little impact on the overall reconstructions. Also, the series was not included in the calibration. Nonetheless, it's unfortunate that I flipped the Korttajarvi data.

In fact that is not a completely true statement either, since, as Mia Tiljander noted, the original data clearly showed an MWP, and if the data was good enough to use inverted to disprove that it existed, surely it should also be used to prove its presence when turned the right way around. But as Steve McIntyre has noted on the subject, while the original perpetrator may have submitted a correction the good Dr Mann has yet to admit that he used data improperly.

Courtesy of Climate Audit, you can judge for yourselves, comparing perhaps to the top figure, as to whether inverting the data made any difference.

How using the Tiljander data properly (New) reveals the MWP and LIA (Tiljander via Climate Audit), while the Team use (Old) hides them.

In further discussion the more recent sediments (which Tiljander noted were disturbed) which upticked in the “OLD” incorrect use, continued to be used by the team. As Andrew Montford noted in "The Hockey Stick Illusion", however:

The big selling point of Mann’s new paper was that you could get a hockey stick shape without tree rings. However, this claim turned out to rest on a circular argument. Mann had shown that the Tiljander proxies were valid by removing them from the database and showing that you still got a hockey stick. However, when he did this test, the hockey stick shape of the final reconstruction came from the bristlecones. Then he argued that he could remove the tree ring proxies (including the bristlecones) and still get a hockey stick – and of course he could, because in this case the hockey stick shape came from the Tiljander proxies. His arguments therefore rested on having two sets of flawed proxies in the database, but only removing one at a time. He could then argue that he still got a hockey stick either way.

And a short P.S. Steve McIntyre has just posted that the Team tried the same nasty tricks to try and discredit Willie Soon at Harvard.

OGPSS - a second look at natural gas in the Bakken

2011-11-22T23:42:00.007-06:00

The comments on the recent post on natural gas flaring drew a few comments, when posted on The Oil Drum that I would like to discuss, before moving on to start reviewing the situation in Russia.

Most particularly I want to discuss the change in the regulations that are now imposed in the Bakken, and then go on to review the alternate ways in which that stranded gas might be used. I would like to thank those who commented, particularly benamery21 who pointed me to the set of presentations in a Webinar that covers the change. There was also a comment by aws-classifieds that led to a Wood Mackenzie view of the current situation.

The Wood Mackenzie view mirrored to some extent what Sid Green and Rockman have both been noting about the current economics of the shale gas drilling bonanza. Harry Flashman also commented. The point is that much of the growth in drilling for the natural gas in shales such as the Marcellus is coming from Joint Ventures, and

the pool of potential shale gas investors has expanded beyond experienced onshore North American operators to include companies willing to commit up to several billion dollars to enter and develop plays. It can be argued that they have neither the skills nor experience to efficiently exploit the resource and evaluate selling gas into the most liquid, dynamic natural gas market, alien to their own typically regulated natural gas markets.   

The continued waves of new investors have committed around US$90 billion to exploiting the shale gas plays in North America, throwing a lifeline to the established players who have been able to continue to hold and exploit their lease holdings using their new investors’ money.

The article goes on to note that the service companies have been making the most out of the current efforts, and as a result companies are beginning to move more of the well servicing in house (including hydraulic fracturing). The article notes, as has been highlighted particularly in comments on earlier posts on the topic, that the majority of shale gas plays are failing to break even at current prices. In consequence it anticipates a market correction, following which only the very best shale gas plays (and that will include those with high liquid content) will survive.

On that note, it is worth looking at the prediction by the North Dakota Department of Mineral Resources at that recent Webinar, which Ben pointed to.

Predicted future oil production from the Bakken shale in North Dakota (ND DMR )

Note that this anticipates that production will only rise by perhaps 150 kbd over current levels. This is perhaps a cautionary tale for those who are looking to see sustained production from these fields of up to 1 mbd through the rest of the decade. DMR sees production declining around 2015, though only at around 1% per year, under a sustained drilling program.

The State, however, notes that 7.6% of the energy value coming from the wells, and 4.3% of the economic value is currently going up in smoke as over 30% of the gas coming from those wells continues to be flared. Regulations do, however, limit the amount of such gas that is flared, through a control on the amount of oil that can be pumped from the well, before it is connected into a gas-gathering network.

Typically, wells are allowed to produce at a maximum efficient rate or MER for a period of time (generally 30-60 days) in order to evaluate the potential of the well and stabilize the production. After such time, the well production is then restricted to 200 bopd (barrels of oil per day) for another 30-60 days, then 150 bopd for an additional 30-60 days, and finally 100 bopd until the well is connected to a gas-gathering system. Further extensions may be granted provided certain conditions are met. But whatever the reason, until that connection is made, the only alternative is to burn the gas.

There is a small catch if the well continues to be flared. If the company applies for an exemption, it can be relieved of paying taxes and royalties on the natural gas flared for a year, but after that taxes and royalties can be imposed – even if the gas continues to be flared.

However one “out” is to use the natural gas to produce electric power – provided that the generator consumes at least 75% of the natural gas from the well. At the same time new gas plants are being constructed, so that, by the end of next year capacity should be up to around 1,000 MMcf/day. The use of on-site generators was also mentioned in the Webinar, though all the presentations are sequenced so this appears lower down the site.

Two ways are proposed for effectively using the gas that is currently flared. The first is a modification to the requirement for electrical generators, with a project by Blaise Energy. There is a case study of an existing operation available, where the company installed a 300-kw generator near one well, and a 340-kw generator by another, in North Dakota. The power is then sold to a local electrical co-operative, and the company now claims agreements to generate 4 MW, with another 15 MW in view.

Generators at a well site, using the natural gas to generate electricity (Blaise Energy ).

The alternate approach, which is being developed by Bakken Express is to capture and condense the natural gas at the well head, and then transport it either to a pipeline or an end user. The initial proposal is looking at five wells, and will generate both Compressed Natural Gas (CNG) and Natural Gas Liquids (NGL) at the well, which can then be delivered.

Skid mounted compressors at a well, separating and compressing the gas. (Bakken Express )

The company uses specialized tube containers to hold the CNG, and to move it to the customer.

Truck used to transport CNG (Bakken Express)

Should the fields be larger, and further from a reliable pipeline (Yamal for some reason pops back into mind, and we’ll get there) then it might be possible, as Sid Green has suggested, that the process might be carried one step further, and the gas liquefied.

For the present, however, with the growth of CNG powered vehicles it is, perhaps enough to envisage that before too long the carriers shown above might become a more familiar sight pulling into the local filling station.

And with that thought I wish you all a Happy Thanksgiving.

El Niño, La Niña and Regional US temperatures

2011-11-20T22:00:00.015-06:00

Changes in the temperatures in the Pacific that are described as El Niño and La Niña events.(NOAA)

One of the increasingly obvious drivers for the weather we’re likely to see over the next year comes from the relative state of the temperatures of the Pacific Ocean. This is generally known as the El Niño effect when the waters are warmer, and La Niña when they are cooler than normal, as shown above. Collectively it is the Oceanic Niño Index (ONI). The effect, over the past 60 years, can be compared with the regional temperatures over that period, derived in an earlier post. Remember that the regional plots were artificially adjusted to move vertically and allow the changes in shape.

A comparison of average station temperatures in the Pacific states (red), mountain states, (dark green), Midwest (light green) and the Atlantic States (purple) with the plots separated by block change in the temperature values for each region, and compared to the Pacific Oceanic Niño Index (ONI) the lower blue filled in line.

The relative importance of the ONI to temperatures in different parts of the world, and particularly Texas, and the derivation of the plot follows.

Considering the volumes of water that are involved, the relative changes in temperatures are quite significant. Consider the current situation, where as we head into a La Niña winter, the temperatures across the Pacific are as much as 1 deg C below normal.

Temperature variations from the average across the Pacific (Australia is in the lower left, the USA on the upper right). (NOAA )

There is a growing recognition that the impact of these changes controls the monsoons in India, going back to the paper published in Science back in 2006 by Kumar et al. This paper explained why monsoon failure always happened with El Niño events, but not all El Niño events led to monsoons. There are thus “flavors” to the events and their results depending on whether they happen in the winter or the summer. The typical impacts, globally, are shown with these illustrations, showing how the timing has influence:

First El Niño:

The changing influence of an El Niño event, depending on timing (after Kumar et al)

India only becomes dry in the second of the two cases, with the monsoon months occurring between June and the end of August, i.e. the lower condition. (And there is also an Arizona Monsoon which might be one of the few areas of the US to be immediately impacted in that case).

With La Niña, the conditions change, and with the event occurring in the summer India gets the needed rain.

The impacts of a La Niña event, depending on timing (after Kumar et al )

The condition that we are moving into at the present is the upper of these latter two pictures, which is not good news for the folk in Texas who have been hoping for rain. NOAA is now predicting that the drought will last into the summer and high temperatures will continue through 2012.

Temperature projections for the next year (NOAA

Precipitation projections for the next year (NOAA )

The impact of these events can, therefore be quite severe. However there is a continual swing from one condition to the other, hence the more broad description of the event that has come into vogue, that of the El Niño Southern Oscillation, or ENSO, or more generally the Oceanic Nino Index (ONI) And the United States sees different impacts in different regions of the country. For example consider the contrast between conditions for the East Coast:

Change in snowfall on the East Coast as a result of ENSO (NOAA)

Change in snowfall in the West as a result of ENSO (NOAA )

There has been some debate in the blogosphere as to what effect this has all had on the US temperatures. Well there are a couple of different points that have to be considered in that discussion, that seem to have got lost in some of the “religious” aspects of the extreme ends of the debate. It has been partially blamed for the high global temperatures in 1998. However, if we take just the last 60 years of data, we can look at how those data fit with the plots that I have previously posted to the site on regional temperatures.

The ONI plot from 1950 (GGWeather )

Now how does this look relative to the temperature changes that have occurred in the US. There are a couple of things to bear in mind on this, that seem lost to the folk at Real Climate. The first is this graphic, which seems to have got lost from the view of most of those who looked at the recent release of pre-papers from the BEST study.

Map of stations in and near the United States with at least 70 years of measurements; red stations are those with positive trends and blue stations are those with negative trends. (The BEST Project).

The second point is the change in temperature profiles (which BEST does not look at, rather concentrating on individual results) for the different regions of the US.

Average variation in time for four regions of the country, with the results adjusted as shown to separate the curves, and show them in order (bottom to top) from West to East.

Using the section of the above plot the regional temperatures were separated, by adding and subtracting from the actual temperatures (as shown in the legend to the above) to get a separation, the section after 1950 can be used to make the comparison.

The ONI plot can now be superimposed below this, with the amplitudes of roughly the same size (since one is in Centigrade and the other in Fahrenheit). The result shows that the ONI (lowered filled blue plot) has some influence on the Western Coast temperature (the lowest red curve), but as one moves through the Mountain states (dark green(, and less on the Midwest (lighter green), with the effects smoothed out by the time they reach the Atlantic Coast (upper purple). The fall in temperature along the Atlantic Coast is emphasized with this plot, and clearly nothing to do with what is happening in the Pacific.

A comparison of average station temperatures in the Pacific states (red), mountain states, (dark green), Midwest (light green) and the Atlantic States (purple) with the plots separated by block change in the temperature values for each region, and compared to the Pacific Oceanic Niño Index (ONI) the lower blue filled in line.

Now rumor has it that something similar happens in the Atlantic?

More pipelines reverse flow as US demand falls

2011-11-19T14:03:00.007-06:00

A recent post covered the plan to reverse the flow of oil along the pipeline that runs sensibly from Detroit to Portland, ME (Or if you are Canadian, since it actually runs most of the way through Canada, from Sarnia to Montreal and beyond). The move is one way of distributing the increasing flows of oil that are being extracted from the oil sands of Alberta, to take advantage of existing pipelines and to meet distributed diemand.

And while the plans for the Keystone pipeline are currently on hold, there is another pipeline which is also being reversed. This is the Seaway pipeline and it runs from Freemont TX to Cushing, OK. It can carry some 400 kbd of oil, and the intent is to have to reversal completed by 2013. This will get around some of the bottleneck that has been building at Cushing, and move more crude down to the refineries along the Gulf. The hope is that it will allow domestic oil to replace some of the crude that is currently imported to those refineries, as domestic production rises to an estimate of 6.4 mbd by 2016. (With that additional rise of around 0.7 mbd from Alberta still, hopefully, coming down to the Gulf Coast as well, by 2015). It is expected that the first 150 kbd may flow by the second quarter of next year.

There are also plans to reverse the flow and increase capacity to 225 kbd with the Longhorn pipeline that runs from El Paso to Houston to carry Permian Basin oil to refineries, by 2013.

Changes planned for the Longhorn pipeline (Magellan)

As these moves are planned, it is worth noting that the demand for gasoline has been falling in the US. This is evident from the latest EIA TWIP. The fall has been as much as 500 kbd, which is significant.

Changes in U.S. gasoline demand (EIA TWIP )

It has even caught the attention of OPEC, in their latest (November) Monthly Oil Market Report, which contrasts the fall over two years, showing the drop from pre-recessionary times. (The peak was 9.6 mbd). OPEC sees overall US demand falling 0.11 mbd in 2011, and only picking up by that amount in 2012.

Fall in summer driving demand for gasoline (OPEC Nov 2011 MOMR)

In passing the MOMR also notes that Russian production of passenger cars rose 46% y-o-y, which may mean that export volumes may fall more rapidly than currently anticipated. Oil consumption in the countries of the FSU is reported at 4.2 mbd, a gain of 0.1 mbd y-o-y. (Sales of U.S. vehicles were up by 10%. ) Their current projections, recognizing the economic problems of Europe, is that world demand will grow to 89 mbd next year, with half of the 1.2 mbd increase coming from Asia, and 0.48 mbd coming from China.

Turning back to the change in driving habits in the United States, the recovery – as evidenced by vehicle miles travelled - faltered and fell back earlier this year, showing the inherent problem still resident in the U.S. economy.

Rolling 12-month average of the vehicle miles travelled on all roads in the United States, through September 2011 (FHWA )

Current declines are seasonal and see to be following the patterns of previous years.

Urban travel on US highways, by month (FHWA )

However there are reports of healthier numbers now coming out of the U.S. economy, and so hopefully, these trends will turn around.

The Icelandic volcano at Katla is becoming yet more active

2011-11-14T20:37:00.006-06:00

I realize that any claims I have as a prophet have faded as the ash that lies on the Myrdalsjokull glacier from the Eyjafjallajokull eruption last year, failed to be blown away under the summer sun. The underlying volcano, that is Katla, while focusing the earthquake activity in the region has done little more than have a relatively small jokulhlaup (or glacial flood) or two. But I can’t help stirring that old pot at least one more time. Because the earthquake activity at the site remains focused in the caldera, and there has been a recent increase in the frequency with which magnitude 3+ quakes have occurred at the site. I was checking on the one that happened last week, and noticed that there are two new ones since last I looked.

Earthquakes in the last 24 hours around the Katla volcano in Iceland (Icelandic Met Office)

UPDATE: The Icelandic Met Office has another page, which shows the quake map in a different mode, and also gives the frequency over the past day. It currently shows an interesting pattern for the quakes of the last 24 hours.

Earthquakes around Katla in the last 24 hours (Icelandic Met Office ) The line follows that of the perimeter of the caldera (the black hatched line).

Note the site also shows the corrected size of the earthquakes, while the earlier site gives an automated assessment. and, as an update, there are consequent tremors that are falling along the same boundary.

The larger earthquakes are also increasing in size, these two being a 3.8 and then a 3.3, occurring about 3 km apart, which with the intervening activity (the red dots) which included a 2.4 suggests that there just might be a fissure opening. (The now corrected values are given in the lower figure).

Three days ago Jón Frímann noticed signs from his geophones indicating that a new dike had intruded into the caldera. The current activity is a little north of that event, it is also very shallow, with the first and larger quake being at 2.5 km depth while the subsequent ones are down around 1.1 km.

OGPSS - gas flares, their significance in Russia

2011-11-14T11:01:00.012-06:00

Over the weekend I went to a talk on the promise of shale oil and gas, given by Sid Green, a friend and one of those members of the National Academy with Washington influence in regard to the future of the fossil fuel business. (He appears much more a Yerginite than a follower of Matt Simmons, as was evident by his conclusion that the fuels from the shale deposits of the country will be our short-term savior. This is a proposition that I have provided some evidence to doubt). However it was in his introduction, by Joseph Smith, the new Laufer Chair of Energy at MS&T, that a slide appeared that is useful to preface where this, the Tech Talk series, will go next. This is the slide:

A poster from NOAA showing the light emitted at night from city lights (white), fires (red), boats are in blue and gas flares are in green. (The picture was put together over the period from January to December 2003.)

It was that large green blob sitting just below the Yamal Peninsula in Russia that caught my eye. It shows the volume of stranded natural gas in Russia that is being flared off because it is stranded, i.e. there is no current way to ship it to market.

UPDATE: I have changed the end of the post to reflect a written answer to my question from Sid Green.

Interestingly, given that preponderance of flaring in Russia, one can also go to a paper given at a Russian meeting where the more ubiquitous size of gas flaring operations around the world is more evident.

City Lights and gas flares around the world, data collected In 1994-95. (city lights in grey, flares in red).

As I noted in a recent post on developments in the Bakken shale, up to 30% of the natural gas that is being produced with the oil is being flared at the moment because there is no way of getting it to market. (And in 1994, note the amount being flared in the North Sea). It is not just a problem for large wells, For many years I drove between Rolla, MO and Crane, IN, spending the night in Vincennes, usually arriving late, with my drive through Eastern Illinois illuminated by flares from the small stripper wells along the way. And it is possible to see flares from the rigs operating in the Gulf of Mexico.

Gas flares illuminating the night in the Gulf of Mexico (NOAA)

In the past Gregor Macdonald has also documented the flares that are found off the coast of Nigeria. . And there was some suspicion that these represented the greatest volume of gas being burned off in this way.

Flares around Nigeria color coded by duration, Those active in 2006 and 2000 are yellow. Those active in 2000 but not 1992 or 2006 are green. Those active in 1992 but not 2000 or 2006 are blue. (NOAA )

A 2007 survey, carried out by NOAA for the World Bank, showed that Russia was burning roughly twice the volume of gas as that lost in Nigeria. A close look shows how the plumes from the flares dominate the Siberian night-time sky.

Thermal plumes from gas flares in Siberia

The NOAA report indicates that around 160 billion cubic meters of gas is flared each year, roughly a quarter of the volume of natural gas that is used in the United States each year. And while countries such as Nigeria have been able to reduce the amount that is flared, countries such as Russia, Kazakhstan and Iraq have increased the volumes flared. (It also explains how the images above were generated). The region of Russia with the most gas flaring is that around the Khanty-Mansiysk region, which accounts for roughly half the Russian total. In 2007 a conference on the subject heard that Russia was flaring around 50 bcm per yer, with Khanty-Mansiysk contributing 24 bcm of this total. (The gas is flared because this is currently where about half of Russia’s oil production is coming from). At that time the goal was set that, by the end of this year, (2011) some 95% of this natural gas should be utilized. There have been a variety of ways suggested to reach that goal. Again, putting the volumes in context, Russia commercially produced some 600 bcm of natural gas in 2006, as well as some 10 million barrels of oil a day.

Flaring around the Khanty-Manysiyski region south and east of Yamal. (World Bank)

At present Russia has reached a new peak in crude oil production of some 10.34 mbd for October, while Saudi production is estimated to have risen to 9.8 mbd. Russia is thus the current largest oil producer, and so it is time to look at where (other than just the region shown above) the oil is coming from, and what the prospects for the future hold for the longer term production, and export of energy from that country.

The natural gas production picture is not quite that rosy, even with the reduction in gas flaring that has been undertaken. Gazprom is reported to have reduced supply as prices in Europe have risen towards $15 per kcf (thousand cubic feet), almost four times that of gas in the United States. Russia as a whole produced some 1.8 bcm/day (63 bcf) of which Gazprom produced 1.35 bcm, both figures down from the same time last year. At the same time domestic consumption of natural gas has risen by some 1.3 bcf/day. Russia supplies about a quarter of European demand, and as production falls off in some of the fields of Western Europe that portion may increase. However the global supply of natural gas is still quite healthy with countries seeking to find domestic sources from the gas shales that might lower their import needs. Thus the power that Gazprom was able to wield just a couple of years ago has now been somewhat reduced.

All of these factors strengthen the conclusion that this series should now move to look at some of the fields in Russia, and given that Dr Yergin has proved to be a better historian than prophet, that probably means that I should go away and re-read The Prize, before it starts. (Though The Quest is an easier read). After all, one wonders how many of us, a week ago, could have found Khanty-Manysiyski on a map?

Location of Khanty-Manysiyski on a map of Russia (Google Earth)

In passing, Secretary Salazar has just announced that permitting will allow the Natural Buttes Project to move forward. Anadarko are expected to develop up to 3,675 wells in the Uintah Basin over the next decade to supply more cheap natural gas into the market, and likely keep the price pressure on the production of gas from gas shales. Which brings me full circle back to the opening of the post, since the question that I asked Sid at the presentation was “How long can the gas shale companies afford to sell their gas at under $4 per kcf, when it is costing them more than this to produce it?”

UPDATE: I had a short snippy version of Sid's reply here, but he was kind enough to send a critique and deeper explanation, which gives a better answer. To summarize his answer, he feels very much in agreement with the points that Rockman has been making in comments on a number of my posts on this topic.

He notes that financing for the E&P companies has recently largely come from "venture capital" money. The companies are able to recover much of their own capex in the first months, but he was careful to note that this did not imply that they are able to make a profit. And with that return they are able to continue on the “tread mill” of drilling another well, and another . . . .

He quoted costs, and noted that a recent WSJ article said that Pioneer was reported to have costs of around $2.48 per kcf. Though if I can interject they are drilling the Eagle Ford and thus the costs may be lower for the gas, since they are, as he notes, making most of the money from the associated liquids. (And Rockman is not that excited about the general situation down there).

However he thinks Haynesville costs are up to $3.50 and Marcellus up to $4.00 or more per kcf. As a result the number of rigs might soon start falling, though he has hopes that with some technical improvements the cost figures might come under better control, and he senses that there are others in the industry also anticipating greater production at lower cost, with some of the better ideas that are being developed. These relate (HO thinks) to better control of the fracture paths induced out into the formations. But without much change operations will move over to more liquid productive areas, and the natural gas situation will not be sustainable as it is.

As an additional side comment there are now animated maps of the Barnett, Bakken and Eagle Ford plays, showing the wells drilled each year, and the production totals, under the Shale Play Development History Animationssections of the EIA map page. (H/t this weeks TWIP which is on the Bakken andEagle Ford.)

The Keystone pipeline - A Canadian response

2011-11-14T08:31:00.004-06:00

Well that didn’t take long! (With a hat tip to Art Berman). I mentioned at the end of the last post that the loss of the oil market through postponement of the Keystone pipeline would not sit well with Canada. The delay in the pipeline removes at least temporarily sales of some 600 kbd of Albertan crude from the Canadian inventory, with the concomitant losses to provincial and national government revenue.

Speaking in Hawaii, the Canadian Prime Minister (who met with the Chinese President while on the island) said:

“This does underscore the necessity of Canada making sure that we’re able to access Asian markets for our energy products, and that will be an important priority of this government going forward,”

And to emphasize the point, while the Canadian Finance Minister has noted that the pipeline plan itself might not survive the delay. TransCanada Corp, who were to operate the pipeline has to retain its customers, even as the Finance Minister flies to China to market energy exports, and perhaps sell the available supply to China. And in the broader scheme of things:

Canada will seek to join a new Asian trade block as it tries to increase energy exports to the region following the U.S. decision to delay approval of TransCanada Corp.’s $7 billion Keystone XL pipeline, Prime Minister Stephen Harper said.

To recap from the earlier posts in the OGPSS series on Canadian pipelines there are plans by Enbridge to build a “Northern Gateway” pipeline from the oil sands to the West Coast. And this has already found support from China. Given the irritation that the United States has just provided the Canadian Government it is worth repeating the comment by the President of Enbridge:

I challenge any of you to name one other country in the world that only has one market for its largest export. Right now our most valuable resource is landlocked in North America and isolated from the world market. That means it is often isolated from world price. The August spread between West Texas Intermediate and Brent Crude, the world price, was $22 per barrel. Canadian heavy crude has more often than not sold at a discount to U.S. light crude that goes well beyond the quality differential – simply because of lack of market.

It should not be forgotten in this debate that the greatest objection to the pipeline seemed to come from Nebraska. Lest you forget Nebraska is the largest producer of corn ethanol west of the Mississippi River. It has 34 ethanol plants, converting 769 million bushels of corn a year into 2 billion gallons of ethanol. (The equivalent of 130 kbd out of the national production of around 900 kbd).

Official map of the planned pipeline from the Department of State.

TransCanada Keystone Pipeline, LLC (Keystone) is proposing to construct and operate a crude oil pipeline from Hardistry (Alberta), Canada to Patoka, Illinois (view map of project). The pipeline will be able to deliver 435,000 barrels per day (bpd) of crude oil to existing terminals in Missouri (Salisbury) and Illinois (Wood River and Patoka). The system capacity could be expanded in the future up to 591,000 bpd.

The proposed project includes 1,073 miles of new pipeline in the U.S. (Keystone Mainline). The Keystone Mainline will be comprised of 1,018 miles of 30-inch diameter pipeline from the Canadian border to Wood River, Illinois and 55 miles of 24-inch diameter pipeline from Wood River to Patoka, Illinois. Keystone may also construct an additional pipeline segment from near the Nebraska-Kansas border to Cushing, Oklahoma consisting of 291 miles of 30-inch diameter pipeline.

OGPSS - A review of North American future production

2011-11-10T21:59:00.007-06:00

This is a good point to recap the intent of the current series of OGPSS articles. Internally, this marks the end of the segment that has dealt with North American oil and natural gas production. The series is not an in-depth review of individual fields but rather seeks to paint a broad background against which to judge the realities of the coming changes in the global supply:demand balance. More detailed discussions are provided by the excellent analysis of such folks as Jean Laherrère, who is even now examining in more detail the production records from the wells in the deep waters of the Gulf of Mexico.

Perhaps more critically, it comes when there are increasing indications that the investment being placed on renewable energy around the world as a replacement for fossil and nuclear power generation might not be adequate to meet the need. For example, this week the British Institution of Mechanical Engineers has pointed out to the Scottish Parliament that their renewable targets for 20% total energy and 100% of electricity production by 2020

did not appear to be supported by a rigorous engineering analysis of what is physically required to achieve a successful outcome in the timescale available.

It is relatively easy for politicians to promise that energy supply is adequate into the foreseeable future. Euan Mearns, for example, has repeatedly written, and guest hosted articles on The Oil Drum which show that supply requires infrastructure and planning over many years, without which (and the absence is evident) those promises become not only unrealistic, but also unattainable.

Just as I wrote this, the White House announced that the decision on the Keystone pipeline would be postponed until after the election next year. In a sense the Administration view echoes the opinion of one of those opposed to the pipeline:

“It’s not like we’ll have an oil shortage,” said Mark Lewis, a partner at the law firm Bracewell & Giuliani who specializes in oil and gas pipelines. “We’ll continue to get product from the sources we get product from.”

If Canadian tar-sands oil moves to Asia, Lewis said, then the U.S. would just continue getting its oil from regions like the Middle East. And the Canadian oil sands would most likely still be developed, with that product entering the same global market.

This series is testing the truth of those remarks and that opinion by looking at the realities of future production and the oilfields that it will come from. As mentioned above, this began with a look at the resources of North America, and it is time to review what was found.

When this series began last April it set out to look at the potential future changes in the North American oil and natural gas supply there were three different parts to that supply. The first is the historic oil, that coming from existing wells and fields, often coming from stripper wells around the country. Then there were the supplies from fields that are currently being developed, and where production is continuing to rise, such as in the Bakken fields of North Dakota and Montana. And then there is the potential that will come from finding and developing new fields in the relatively near term. Perhaps as an indication of my own “Oops” moment, I used the Energy Plan proposed by Governor Perry to illustrate the potential future additional fossil fuel that might be available over the next two decades. That was very similar in promises to a Wood MacKenzie Report prepared for API, and released in September. To give my comments on those projections, I will look first at the summary of projected increase in oil production from that report. This is divided into two parts, the first assumes that current policies continue, and it sees energy supply growing as follows:

Total US Production – using current conditions. (Wood Mackenzie )

The plot shows an increase in oil production from 2010 to 2030 of some 1.2 mbd, which in the overall scheme of things is not really that much change from the present over the twenty year time interval (0.7% per year). Natural gas, on the other hand is expected to rise some 14.4 bcf/day (1.2% per year) which is a little more impressive.

However, if all the wishes of the industry were to come to pass, (the development policy case) then Wood Mackenzie sees considerable potential for supply growth.

Production with an accelerated development program (Wood Mackenzie )

In that developed condition Wood Mackenzie sees oil production increasing 7.6 mbd to 15.4 mbd by 2030, while natural gas production rises by 36.8 bcf/day to 96.9 bcf/day.

The first concern that I have with these plots is that of the declining reserve. In previous posts I have discussed various estimates for the decline in production that occurs in existing wells over time. This occurs with both oil and natural gas wells, and changes with rock type, well type and other factors. For example a recent post by Fractracker on the performance of 756 Marcellus wells notes that horizontal gas wells declined an average of 39% in the last year, while vertical wells declined 47.6%, though those numbers do not reflect wells that were closed because they were no longer producing (16.7% of the horizontal wells and 6.9% of the vertical wells). Figures from other gas shales have reported decline rates in the Haynesville, for example, of 85%. In conventional oil wells (and reservoirs such as the Bakken are, for this discussion, considered as unconventional) the decline rates now lie above 5% . What this means for US production is that, just to stay even, the industry has to add at least 360,000 bd of new production each year, to maintain a roughly 7.2 mbd level of total oil production. (and that is likely to be, at best, the average gain in production over the next ten years from the Bakken and Niobrara combined).

So where does Wood Mackenzie see the gains in production from the “development” case?

Regions where additional production may be obtained (Wood Mackenzie )

The problem that the map shows is that much of the new discovery and development is anticipated to come from the offshore, whether it is East Coast, West Coast, Gulf of Mexico or Alaska. In comments on the post discussing drilling off the Atlantic coast, my quote on it taking four to ten years for production following the start of leasing led to kindly admonishment by Art Berman, Harry Flashman and Rockman on the overly optimistic view that this represented, with the reality of development being more likely to occur over decades. This holds even more true for resources off the Alaskan coast, where the on-land infrastructure is not currently in place. And it fails to recognize the antagonism that state governments (such as those I mentioned from New Jersey) have to offshore drilling on both coasts.

The current increase in oil production in the United States is, in part, due to the development of long horizontal wells, with multiple fractures along those wells to improve flow to economic levels from shales that were previously uneconomical to drill. As long as enough production can be achieved from such wells to keep them viable for the oil industry they will be developed. When they cease to be then they won’t. The rapid decline rates that are found for these wells (as was shown in the posts on Bakken and Niobrara) mean that as production moves from the sweeter spots in the reservoirs out to the leaner fringes, a point will be reached, in a few years, where those economic factors will come into play. As that time approaches the price of oil (for a variety of reasons) will be sufficiently higher than it is today to encourage greater overall production than might be anticipated from today’s figures, but it will be nowhere near enough to meet the levels of US demand. And it will still curtail overall production.

The gain in production that Wood Mackenzie sees in moving to the “development phase” does not really kick in, were all things to come to pass, until about 2016. And even then the main initial gains are assumed to come from the easing of regulations, which is, I rather suspect, a wish, rather than any reflection on what might realistically happen.

Possible gains in future production over the current condition (Wood Mackenzie )

The delay in granting permission for the Keystone pipeline will shift some 700 kbd of US supply out another year at least. But that does bring up the issue of the oil sands. They are the one source where the deposit size is known and adequate, and where gains to help meet demand could be achieved. However, with the delay and possibly even denial of the pipeline, it is now quite possible that the Canadian Government and the other parties concerned might hear again the same blandishments from China that persuaded the Turkmen, and when we finally get around to giving grudging permission for Canada to sell us more oil, that additional tar sand oil may already be heading overseas through pipelines running west.

Whether, at that point, we can then

continue to get our oil from regions like the Middle East

is a point that I will look at as this series continues, and we start to examine the long term potential of sustained oil supply from regions overseas.

Oh, and a quick P.S. for those who remember the post on the Alaskan pipeline, in August it was running at an average of 538,623 bd, with the annual average now running at 568,471 bd.

OGPSS - Drilling off the Atlantic Coast

2011-11-04T00:35:00.007-05:00

When the Presidential Administration changes, particularly when that change involves different political parties, the results on energy policy, and ultimately energy availability and price can be, but are not always, significant. In recent posts I have cited Governor Perry’s Energy Plan were he to come to power, and have noted that, for some issues, the change in power may not have much effect. This is particularly true where the energy reserve is already being produced, with production levels being, to a degree, controlled by things such as price, rig availability and the potential promise of a well.

But there are some regions of the country where the policies of the Government can have a greater impact on potential production. And the last region that I have left to discuss of those included in the Governor’s Plan, that of the Outer Continental Shelf (OCS) and particularly that off the Atlantic seaboard, is one such. It is not, however, only Governor Perry that recognizes the potential promise of the region. This is a theme that ex-Speaker Gingrich, another Presidential candidate, has also sounded. His remarks were directed at the benefits of dredging Charleston’s port, thereby supporting the OCS activities and potentially adding 8,800 jobs in S. Carolina.

The most likely first area to be leased is that off the coast of Virginia, that was designated as Lease Sale 220.

Region designated for Lease Sale 220 by the Department of the Interior, in November 2008. (Bureau of Ocean Energy Management, Regulation and Enforcement )

At the time it was estimated that the area might contain 130 million bbl of oil, and 1.14 Tcf of natural gas.

President Obama had continued support, proposing to open the Atlantic Seaboard to drilling back in March, 2010. Unfortunately while the initial plan bad been for lease sales to begin off the coast of Virginia this year, that was put on hold with the Deepwater Horizon disaster.

Following the sealing of the well in the Gulf, and after due review, the Department of the Interior released a statement last December that noted, relative to the Atlantic and other locations:

Based on lessons learned from the Deepwater Horizon oil spill, the Department has raised the bar in the drilling and production stages for equipment, safety, environmental safeguards, and oversight. In order to focus on implementing these reforms efficiently and effectively, critical agency resources will be focused on planning areas that currently have leases for potential future development. As a result, the area in the Eastern Gulf of Mexico that remains under a congressional moratorium, and the Mid and South Atlantic planning areas are no longer under consideration for potential development through 2017. The Western Gulf of Mexico, Central Gulf of Mexico, the Cook Inlet, and the Chukchi and Beaufort Seas in the Arctic will continue to be considered for potential leasing before 2017.

However

Because the potential oil and gas resources in the Mid and South Atlantic are currently not well-known, Interior will move forward with an environmental analysis for potential seismic studies in the Mid and South Atlantic OCS to support conventional and renewable energy planning. No lease sales will be scheduled in the Atlantic in the 2007-2012 program or in the 2012-2017 program.

The current emphasis has been on the Mid-Atlantic States, particularly Virginia and South Carolina, where there is support for the idea. In contrast, New Jersey has expressed concern over the risks of offshore drilling in the past and Governor Corzine was particularly outspoken against offshore drilling or leasing acreage, feeling that it would threaten the tourism and fishing industries of the state. Governor Christie (who replaced Governor Corzine) has retained that opposition to drilling off New Jersey, but is apparently not as passionate about states further south.

The OCS was first surveyed by the USGS back in 1974, and from 1976 some 40 wells were drilled, though none brought in commercial quantities. President Carter approved a 5-year leasing plan in 1980 that saw an additional 50 leases sold over the next two years. But in 1990 President Bush withdrew the Atlantic OCS from lease potential. That action was in process of being reversed at the time of the GOM oil spill. ( Linda Bennan. )

The possible change in the party that holds the Pesidency might therefore influence the opening of leases to develop the Atlantic OCS. Given however that it was a Republican President who withdrew the acreage in the past, and that it has been advanced by Democratic Presidents, that is not necessarily a conclusive declaration. That is particularly the case given the objections of some of the Republican Governors.

But even if the decision is made to go ahead, the EIA consider that it will take at least four years from the sale of leases until production from any identified reserves can be begin, and in some cases such an interval is considered optimistic. (Art Berman has pointed out that the sequence of first carrying out new seismic work, then drilling an initial well, followed by appraisal wells, if that first well were to be successful, and then the construction of production platforms would likely move the timeline out closer to ten years). Estimates of the total oil and natural gas available vary quite widely, The BOEMRE thinks that there is 0.5 to 1 billion barrels of oil in the Mid Atlantic and 0.03 to 0.15 billion barrels in the South Atlantic. But with the slow rates of development it is unlikely that the production will exceed the estimate of the EIA, which foresaw some years ago, that this new OCS production might possibly only stabilize production of offshore oil.

Projected OCS production (2007) (EIA )

It was not expected to stabilize offshore natural gas production.

Lower 48 offshore NG production with and without increased OCS (EIA )

In which regard, the model that the EIA use in predicting production from these fields is:

For currently producing fields, a 20-percent exponential decline is assumed for production except for natural gas production from fields in shallow water, which uses a 30-percent exponential decline. Fields that began production after 2008 are assumed to remain at their peak production level for 2 years before declining.

In passing lease sales are anticipated to restart in December for the Gulf of Mexico in waters ranging from 16 to 10,900 feet deep. The prospects are considered to have the potential to the production of between 200 and 450 million barrels of oil, and 1.5 to 2.65 Tcf of natural gas. However minimum bids for the acreage bave risen from $37.50 to $100 an acre.
(H/t Gail and Art)

BEST and a growing controvery.

2011-10-30T02:34:00.003-05:00

Some time ago it appeared that the Berkeley Earth Surface Temperature (BEST) Study was going to be a new review, critically supported by both those that believe in Anthropogenic Global Warming and those more dubious about the quality of the data that had led to that conclusion. The first papers have been released, and the controversy over what they found, which seemed relatively minor at the beginning, is now starting to get some notice.

Bishop Hill has drawn attention to an article in the London Mail on line in which Dr. Judith Curry voices concern about the papers and the way the information was released. Up in Canada, Steve McIntyre is raising more points of concern in successive posts at Climate Audit. And within the comments at both sites there are further growing areas of contention being identified.

I have, as those who read the individual state reviews that have been posted here over the last two years (and which are listed down the left side of the page) my own concerns. I have sent these to the attention of the BEST Executive Director. To validate their reality I went back to each of the data tables used to generate the graphs for each state, and checked them for correctness. I found that at the beginning the curves for temperature variance with latitude, longitude , elevation and population had included the temperatures for the GISS stations in a state as well as the USHCN station data. This is a mistake, as the continuing study showed how different the two sets of data are. I have thus re-plotted the data using only temperatures for the USHCN set (both homogenized and for the TOBS data).

I will now go back and change the plotted graphs for each state to make sure that they are the correct ones, but this may take a few days, so in the mean time, please be patient.

In the meanwhile you might ponder this plot which is figure 4 from their paper on the Urban Heat Island Effect.

Map of stations in and near the United States with at least 70 years of measurements; red stations are those with positive trends and blue stations are those with negative trends. (The BEST Project).

Katla, volcanic ash, and other opinions on the effect of climate,

2011-10-28T01:52:00.005-05:00

There has been an interesting set of quotations over on Dr. Curry’s Website which led back, through a post by Roger Pielke Snr to an article by Paul Voosen abouhow the changing aerosol and particulates in the atmosphere could be helping to control climate. While not wishing to get into that debate at the moment, (though the quotes are interesting, and should be read in context) one of the “complaints” of the scientists has been that there has not been a major volcano, with a significant impact on climate since Mount Pinatubo erupted in 1991. In that case, the second largest eruption of the 20th Century, ejected some 20 million tons of fine ash and sulphur dioxide into the upper atmosphere reducing global temperatures by about 1 deg F, for a couple of years.

In the current article one of the scientists at the Mona Loa observatory (John Barnes) has been monitoring the particulate content of the stratosphere and has noted that the count is going up, without such a major eruption. And it is that fact, discovered four years ago, that then leads into a discussion as to why the world isn’'t heating as fast as has been predicted. (In which discussion no-one brings up the new BEST study and the fourth figure in the Urban Heat Island paper which shows that large sections of the United States have had a negative, rather than a positive trend over the period of study. (Not that readers of the state temperature data given in posts listed on the lower right column will find that a new discovery – see for example, the discussion on the temperatures of the “Flat Middle”.

Which is, in itself, a good lead in to noting that Katla just earned another two stars (signifying earthquakes greater than 3.0 – with one being in the crater and one to the North-West towards the area of intense activity earlier this summer.

Earthquakes at Katla in the last 24 hours (Icelandic Met Office )

It is not that this necessarily brings this eruption much closer, though the smaller quakes are clustering again and Jon commented that there does not appear, as yet to be much harmonic activity (signifying significant magma movement ) yet, though there may be a small dyke intrusion into the caldera.

The question at the moment, I suppose is as to whether it will be the clustering that can be seen here under the right-hand star (the +3 quakes) that will intensify prior to the quake, or whether we will not get a major eruption until that cluster spreads to cover a broader region around the caldera. There are arguments on both sides.

But this may be the future source of some of those particles that John Barnes continues to seek, if the eruption lives up to some of its previous history. At the moment all we can do is wait and see whether the eruption comes this year, or not, and if it does how it will answer the question.
.

OGPSS - the Niobrara, the Tuscaloosa and the Chatanooga

2011-10-26T23:43:00.009-05:00

When Governor Perry recently released his Energy Plan, I noted in my review, that it bore a close resemblance to the position paper prepared by CERA for the API, and that it could be, in consequence, considered perhaps the “best shot” of the oil and gas industry in predicting where new North American resources might come from in the next couple of decades. One distinction that I did not make, and that is somewhat difficult to decide, is the extent to which these events will come to pass, regardless of who is the next President.

If one looks at the different regions that are suggested as sources to increase oil availability for the United States, I have largely discussed the various options, whether the Bakken Shale, the off-shore resources of Alaska and of the Gulf of Mexico, and the gas shale reserves such as the Marcellus. One of the two regions and resources I had not covered was the increase in production that can be anticipated from the Niobrara shales of Colorado, Wyoming and adjacent states. (The other is the offshore Atlantic). Since this is a new enough development that it may not be well known, I thought to mention some basic information about the Niobrara in this post.

The development of fuel sources from the fine grained shales that cover much of the country has been one of the great success stories of the past decade, and the proliferation of natural gas that it has generated has helped keep the price of that critical fuel low, thereby providing an advantage to American industry. And if one looks at the shale plays potentially available around the country, there are a number that have yet to be developed significantly. I am not sure why this was singled out relative to a couple of others as being the only likely benefit of the Governor’s attention, nor what gains would be made in terms of either production or jobs from any action the Governor might make as President, given that, in the same way as with the Bakken, the drivers are much more likely to be geologically and oil-price driven than they are regulatory, particularly at the Federal level.

Shale plays around the contiguous United States (EIA).

The most likely of still relatively inknown resources (outside the Niobrara) to be developed in the near future may well be the Tuscaloosa, and the Chattanooga. The Tuscaloosa has been vertically drilled back in the 1960’s and since but with the potential to have similar attributes to the Eagle Ford, i.e. a liquids rich resource, it has a marketable product in those liquids that may make it more attractive. Exploratory drilling has begun, with two horizontal wells slated to be completed this year, at a cost of perhaps $8 million apiece to reach the reservoir and extend a lateral running out about 7,500 ft. Whether the production will make it possible to profitably cover those costs remains yet to be determined. The reservoir varies from 200 to 800 ft thick and lies at depths between 11,000 and 14,000 ft. The reservoir may contain as much as 7 billion barrels of oil.

The Chattanooga, on the other hand is a relatively very shallow gas play which may make it easier and less costly to develop, particularly if existing wells can be deepened. In relative terms the oil production anticipated is only as yet (from vertical wells) on the order of 6 bd, with 25 – 300 Mcf of natural gas. It is not, in short likely to bring significant production to the table – at least on the basis of current prospects.

And this is where the Niobrara has the greater potential. It is considered to be somewhat similar to the nearby Bakken, which has now reached production levels reportedly of around 400 kbd, with production varying between around 150 to just under 600 bd/well.

Peak well production rates in the Bakken (EOG Resources )

The Niobrara is not a continuous reservoir, but rather broken into a series of smaller sections:

Niobrara locations in some seven states in the West (OGJ )

The production numbers are still somewhat tentative, given the small number of wells that have been produced, but EOG reports from its wells in Colorado for example, one well with an initial production of 645 bd, though that has now fallen to between 300 and 250 bd, while a second is now running at 225 bd. The company is planning a total of 45 wells this year. Further north in Wyoming Entek is reporting low oil flows even before fracturing.

Well costs are reported to be between $4 and $5.5 million for E&D in drilling down to the reservoir which lies in the 7,000 to 8,500 ft depth and then completing a horizontal section of perhaps 4,500 ft with perhaps 18 stages for hydraulic fractures.

Anadarko plans for development of the Niobrara

Anadarko, which is reported to have one well that initially produced at 550 bd, is expecting to run between 1 and four rigs, building up to a production of around 16 – 20 wells per rig per year on a 40 acre spacing. The Wyoming section of the Niobrara currently has some 13 rigs, while the Bakken in North Dakota has around ten times that number. Rigs are, however, also reported to be in short supply.

(There is an Anadarko video)

The story would not, however, be complete if one did not note that China is also aware of the play, and in January bought a third of the Chesapeake Niobrara operation. Given that one of their wells came in with an initial production of 1,270 bd of oil, and 2.4 mcf of natural gas, Chesapeake seem to retain their ability to find the sweet spots in reservoirs., relative to others for whom the 200 – 500 bd average is more typical.

And a final reminder, from the Bakken post, of the relatively short life that can be found for a typical well producing oil from a fractured shale deposit.

Typical Bakken well production (ND DMR )

The Delinquent Teenager - the IPCC and the WWF

2011-10-24T14:56:00.004-05:00

I mentioned last week that Donna Laframboise has just written a new book with the lengthy title “The Delinquent Teenager Who Was Mistaken for the World's Top Climate Expert”, but which, for this post I will shorten to “The DT”. The book is a fascinating dénouement of the reality of the structure of the Intergovernmental Panel on Climate Change (IPCC). The IPCC issues reports which it describes as:

an update of knowledge on the scientific, technical and socio-economic aspects of climate change.

Four reports have been issued to date, with work ongoing on the fifth, which is referred to as the Fifth Assessment Report (AR5) and which will be released in the 2013/2014 timeframe. The book deals with the way in which the current report, AR4, released in 2007, and which might be considered the “Climate Bible” (Donna’s words) was compiled, and the makeup of the writing teams for AR5.

The work is widely reported as being that of the world’s experts in the different aspects of climate, and its impacts, with the assessment reports bringing those ideas together under the supervision of panels of additional experts in the various fields. Thus it is claimed to summarize the opinions of thousands of scientists and to mark the quintessence of thinking on the state-of-knowledge. With that reputation it is quoted as the justifying document for a wide ranging set of governmental actions around the globe, including the move by the EPA to control Greenhouse Gases, and for example, the moves in Europe to restrict the use of coal in power stations and to justify the increase in investment in wind and solar energy technologies.

But that curtain of respectability based on the “authority” of the authors has been shattered through the revelations of the book. And while it should be noted that many of the individual facts have been discussed in the past, they have never been chained together to shake the edifice so thoroughly and justifiably as is done here.

There are, of course, those who will denigrate the work, the World Wildlife Fund (WWF) has issued a press release in which if “refutes ‘ludicrous’ claims’ that it infiltrated the IPCC. However, the power of the book comes in the detail that allows me to look up the role of the WWF. Chapter 4 of the report of Working Group 2 deals with species extinctions, and it has five of the 10 most senior personnel affiliated with the WWF. The WWF has, as Donna notes (and details) worked to persuade IPCC authors to join one of its panels, and she goes on (in footnote 31-5) to list 78 IPCC personnel who have thus become involved. (Also on her Website). The facts deny the WWF protestations.

But it is in the revealed mediocrity and mendacious nature of the reports themselves that The DT is most disturbing. Rather than relying purely on the skilled knowledge of the world’s experts, and their papers, as the IPCC claims is the practice, considerably less upright behavior is documented throughout the book. Very junior scientists are recruited to draft significant portions of the material, and many documents used turn out to be from non-peer-reviewed sources. It is not that I am necessarily impressed with “peer review”, as an academic I have very mixed feelings about those who consider that nothing is established until it is in a peer-reviewed publication – despite physical evidence or other real world experience - but if you claim that the material is peer-reviewed and as is shown here it is not, then you are at best proven unreliable. The actions of the “Team” in filtering papers that try to get into such journals, and the consequences to those who doubt the “Climate Bible” and the editors who publish them are now well documented in books such as Andrew Montford’s “The Hockey Stick Illusion”, and the Mosher and Fuller book “Climategate: the CRUtape letters” . The "gatekeepers" to the journals are working hard to ensure that only their views are heard, thus the value of these books.

The DT illustrates, for example, the actions of Kevin Trenberth, who with little documented background knowledge in the area of the possible effects of climate change on hurricane intensity, led that chapter of the Climate Bible, and in the process over-rode the expert knowledge of Chris Landsea, who had commented “there are no known scientific studies that show a conclusive physical link between global warming and hurricane frequency and intensity.” (The full e-mail with this objection is a Webcite within the electronic version of the DT).

This really is a highly informative, well documented look at the IPCC which deserves wide distribution, and it should be read by all those who cite the IPCC as justification for a multiplicity of processes. Sadly to say, I rather doubt that it will get the hearing and the proper respect that is its due. What has become evident over time is that the pathways to “getting the word out” lies through a band of “environmental reporters” who would not have work if there were no “environmental crisis.” Rather than review opposing viewpoints or disquieting information, such as that found in this book, their practice has been to ignore the message in the hope that it will go away. After a while they can then say “oh, but it was brought up, and really it was but a storm in a teacup!” They then move on, blissful in their disregard for anything but to maintain a status quo that keeps them gainfully (???) employed.

I would however suggest that it is well worth taking the time to understand what foundation the IPCC is built on, because there is, in all things “ a time when all things come to those who wait.” And as the ball of that discontent grows you will be able to understand both its context, but also what other legs of straw will also fall, in time, as the edifice crumbles. This is a worthy beginning to that eventual result. It is unfortunate that the world could not hold out for a change in IPCC structure, that would allow the true picture to emerge, but as the book shows, the powers that are entrenched have their own agenda, and the controls to maintain it . . . for the present.

U.S. temperatures and the BEST study

2011-10-23T22:58:00.003-05:00

For those who have been following my review of the temperatures around the United States, there was an interesting set of papers released by the Berkeley Earth Surface Temperature (BEST) study in the last week. Four sets of findings have been released, based on:
1) statistical methods
2) Urban Heat Island
3) Station Quality
4) Decadal Variations.

For the moment I am most interested in the second of these, since it relates to the effect of population around the measuring station on the resulting temperature reported. This is not quite the same as the UHI effect, although they are both generated by the same factors.

In the paper, to greatly over simplify, the authors appear to have looked at the trends in temperatures in urban and rural sites, and then looked at the difference between the trends in temperature since 1950 for each. They report that the overall trend (i.e. temperatures in urban areas – temperatures in rural areas) is negative rather than the expected positive. They find an average negative trend of 0.342 deg F per hundred years. (Or 0.00342 deg F per year).

I have a couple of concerns about the results they have reported, which requires that I carry out some comparative plotting of my own to generate similar trends. Since I will be looking at the 48 contiguous states (though some will drop out as being too small) this will take a little while. So I ask you to bear with me if posting is a bit sparse while I run these numbers.

OGPSS - Governor Perry, an Energy and Jobs Plan

2011-10-19T00:07:00.011-05:00

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.

A new book and the temperatures in the Mountains

2011-10-16T23:24:00.014-05:00

One of the many significant salient points that Donna Laframboise makes in her new book on the IPCC lies in the predilection of the IPCC authors to rely on computer modeling over factual data. I will probably have more to say on this in my planned review of the book (which so far is fascinating to read and damning in the details) once I finish it, but it does suggest that posts such as these on the actual variations in US temperatures over the past century will languish in outer darkness – oh, well!!

To recap where we are, after looking at the temperatures of the individual contiguous states of the American Union, I have started to look at regional changes and to compare them. A significant drop of around four degrees Fahrenheit that occurred between 1950 and 1965 along the Eastern Seaboard, and which inter alia led to a southern migration of the black-capped chickadee, has since been reversed in the warming of that region post-1965. In contrast in the middle of the country there has been sensibly no warming trend since 1895 (which might explain why the Governor of Texas finds it harder to believe in global warming, since his state hasn’t seen any).

Yet on the West Coast the trends show a relatively consistent increase in temperature since 1895. And so the next place to look is to see what happened in those states that lie along the Rockies and provide the mountainous barrier between the West and the Middle. In the following post I am going to derive this graph, and comment along the way as I get there.

Average variation in time for four regions of the country, with the results adjusted as shown to separate the curves, and show them in order (bottom to top) from West to East.

For this exercise I am going to include Montana, Idaho, Wyoming, Nevada, Utah, Colorado, Arizona and New Mexico . I have previously used both the homogenized data from the USHCN and the Time of Observation corrected (TOBS) data, with a preference for the latter since, as I noted with the individual state evaluations, it has shown a consistently better correlation across the states with latitude and elevation than the data after manipulation.

Combining first the average temperatures for the states, using the homogenized data, one gets a relatively flat curve, but one with a decided kick over the last thirty years, the sign that many consider the marker for Anthropogenic Global Warming.

Average of the state temperatures for the Mountain Region, averaging the values for the different states in the region.

However, before there is much comment on this, it should be noted (when this is compared with the figure above it) that that trend is not as clear in the four regions as I ultimately graphed them. But before getting to that let me just put up a set of comparison graphs, using the USHCN homogenized data, to show that the temperatures of the eight states that I looked at appear to vary relatively consistently. By setting them one above the other it should be easier to cross-compare.

These are relatively consistent, though they appear to smooth a bit with movement south, but to get back to that kick in the end of the plots. As you may know, and I have commented in the individual state plots, the USHCN data is “homogenized” from the raw data. When one takes the average of this “manipulation” and subtracts the Time of Observation corrected values from it, then one gets this curve as the average change made by the climate scientists in reporting the values for the stations in the evaluation (all 233 of them).

Difference between the average USHCN homogenized temperatures and the raw temperature averages, as corrected for time of observation (the TOBS values).

Given that, the rest of the analysis will go back to using the TOBS values. Firstly this changes the average a little:

Average temperatures for the Mountain states, using the Time of Observation corrected raw data.

The change in the slope of the curve drops the rise in temperature per century from 1.7 deg F to 1.08 deg F.

However this curve was obtained by just averaging the average state temperatures, there are varying numbers of stations and varying areas for the different states. When one weights the value by the relative number of stations in the state (equivalent to averaging all the stations in the region), then one gets:

Average temperatures for the Mountain states, using the Time of Observation corrected raw data and averaging the 233 stations in the region.

In each state, the area that each station “covers” (i.e. the area of the state divided by the number of stations) varies from 8,500 sq miles in Nevada, to 2,123 sq miles in Utah. To try and account for this I have weighted the state values by the areas of the states, and this gives this plot:

Average temperatures for the Mountain states, using the Time of Observation corrected raw data and weighting the state averages by the area of the state.

With this plot the steadily increasing temperature suggested in the USHCN plot does not appear as evident, and the temperatures since about 1990 seem relatively steady.

So how do the regional values now compare?

Comparison of average temperatures for the different regions of the United States (as I have defined them)

Obviously the mountain temperatures are lower than those of the other regions given that there is a fall in temperature with elevation. For the combined region this looks like this:

Variation in state temperature as a function of average station elevation in the state.

The r-squared value is much lower for this than it is for the individual stations in the region, and so I will have to look at the effects of latitude, elevation and population separately.

But to conclude I wanted to see how the temperature patterns changed across the country, and the overlay of the regional temperatures made that a little difficult to see, so I “shifted” the curves by adding and subtracting temperatures from each set, so that the comparison of shapes could be made, and that is where we came in:

Average variation in time for four regions of the country, with the results adjusted as shown to separate the curves, and show them in order (bottom to top) from West to East.

OGPSS - the future of oil sand production in Alberta

2011-10-13T20:29:00.009-05:00

If one examines the forecast future supply of liquid fuels that the EIA projects in their most recent International Energy Outlook, that for 2011, the agency projects a considerable growth in unconventional supplies of liquid fuels.

EIA projections of future growth in liquid fuel supplies (EIA)

For North America, the projections foresee considerable growth both in production within the United States (rising from 8.5 to 12.8 mbdoe) and from Canada (rising from 3.4 mbdoe in 2008 to 6.6 mbdoe in 2035).

Regional growth in liquid fuels generation 2008 to 2035 (EIA )

The growth in unconventional fuels is most critically anticipated as coming from oil sands, with biofuels (a topic for another day) close behind.

Future sources of unconventional liquid fuels (EIA )

It is, in passing and for folks such as Dr Yergin perhaps, worth noting that the EIA does not see much of a significant role for oil from shales through 2035. But it highlights the criticality of the Athabasca oil sands in the future well-being of the North American fuel supply chain.

There have been a significant number of posts, over the years, both at Bit Tooth and at The Oil Drum, in which both myself and others have written about these reserves that are playing an increasing part in North American oil supply, and that will likely also grow to supply other nations, particularly China. (A topic dating back to the start of The Oil Drum). In this particular post I will therefore just briefly overview the reservoirs, and the technologies used to extract the fuel, in looking at the projected outlook for the future – given that this has been reviewed and changed a number of times in the past. Some measure of that variation comes from the predictive curves that Sam Foucher posted back in 2006.

Predictions of oil sand production from 5 years ago (The Oil Drum )

Considering first the resource, the amount of oil that exists within the oil sands of Alberta has been estimated as being between 1.7 and 2.5 trillion barrels. It is found in three major deposits the largest of which is the Athabasca, and then there are Cold Lake and Peace River.

Locations of the major oil sands in Canada (CAPP)

There are several different ways in which the oil can be recovered, of which the one generating the most visibility is where the sands lie close enough to the surface that they can be mined. Early use of single, large-scale bucket wheel excavators did not work out well, since production is tied to the well-being of a single machine. As a result the sands are mined by perhaps 15 shovels within the mining pit, each scooping about 100 tons of sand at a time, and loading trucks, which then carry the material, 300 tons at a time, to an in-mine crusher which breaks the rock into small fragments. These fragments (with waste rock largely removed) are then mixed with hot water and pumped to large tanks at the primary Upgrader, where the sand, water and bitumen are separated.

Loading a truck, it will take 2 to 4 shovel loads to fill the truck bed, depending on its size.

There is a Youtube video of the process available.

The sand also contains small particles of clay, which are difficult to settle out of the water, and the large tailings ponds used for this have been the focus of considerable controversy. This concern is recognized, and considerable efforts are being made to reduce the time that it takes for the settlement, and for site reclamation. That effort is continuing with a collaborative effort between the mining companies and four universities to improve the technology over that currently used.

Some 80% of the reserves lie too deep for mining to be an effective solution, and with the bitumen being, in natural form, too thick to easily flow to wells, ways had to be found to encourage that flow. The most common, and that most often projected for future development, is based on the use of Steam Assisted Gravity Drainage.

Artist's illustration of the SAGD process (Devon Canada Corp)

There is a video of the SAGD process on Youtube.

One of the problems with SAGD comes in the need to generate the steam that is fed into the upper pipe, and which migrates up into the sand to heat and thin the oil. The typical method to provide the steam is with natural gas, and as Dave Cohen noted some years ago, the supply of that natural gas becomes more of an issue, as the size of the operation continues to grow.

One of the more innovative of the techniques suggested overcomes that problem through burning some of the oil in place, in a process known as Toe to Heel Air Injection (THAI) . Igniting a section of the oil sand, and after using the heat to drive off the more volatile oil while continuing the burn with residual coke left behind, as the flame front progresses, has been shown to be viable.

It is an artist’s impression of a side view of the site, with the blue dotted horizontal line representing the recovery well and air being fed in from a higher well into the formation.

The video showing the THAI process is also on Youtube.

However, at present it has only a limited planned future, though that may increase as information on the technique becomes more evident.

So what is the likelihood that, using these techniques, that production will rise to the levels which the EIA project? Well in their October 3rd edition the Oil and Gas Journal (OGJ) listed (registration required) those projects currently planned for Canada in the period through 2020 and beyond. The list contains 144 projects, many of which are defined as the separate stages of different developments. Taking just those that relate to oil sand production roughly 70% plan on using thermal methods to recover deeper oil (mainly SAGD, though there are small amounts of THAI, cyclic steam and electrothermal). 30%, roughly 2 mbdoe, of the increase in production is planned to come from surface mining.

It is unlikely that the total 6 mbdoe of increased production will all come to pass. However, given that these are all defined projects, many broken into separate phases that can be geared back or advanced, depending on market conditions, and supply – particularly in the further out years – the projected increases that the EIA project would seem to be eminently reasonable to anticipate. (Caveats on water and natural gas availability are discounted at present).

I would be remiss in not thanking HereinHalifax who led me to the report on Eastern Canadian supplies, which pointed out that the flow of crude in the pipeline from Sarnia to Montreal, about which I wrote earlier, was originally Eastward, carrying western crude, but which was reversed as the market for the oil from Alberta developed in the United States, and Eastern Canadian refineries supply switched to tanker import.

The increasing plans to produce oil from Alberta depend, to a degree, on the ability of pipelines to carry the resulting product to market. Production is therefore likely to hinge on the success with which those advocating the various pipelines are able to achieve. And to a coonsiderable extent these are political, rather than technical decisions.

Postscipt: Emmanuel has pointed out that when I discussed the fields in Eastern Canada I did not mention the Old Harry Field, which has been the subject of much debate between Quebec and the Federal Government and which may be twice as large as the Hibernia field. With apologies (and thanks to Kristin) here is the location:

Location of the Old Harry Field (Source Evidentia)

Regional US temperatures, the West, the Middle and the East

2011-10-05T22:42:00.009-05:00

The relative changes in the temperature profiles between the Central States and those along the Atlantic Coast, begs the question as to the relative conditions on the West Coast. And so I have combined the state temperatures of California, Oregon and Washington State. As with the other regions the first average that I took was for the homogenized data, and just took an average for the three states, to get a sense of what has occurred over the past hundred and ten years.

Average temperature over time for the Pacific Coast, using the average of state temperatures, and homogenized USHCN reported temperatures

The most obvious immediate conclusion is that the temperature drop from 1950 to 1965 which is so evident on the East Coast does not appear to have happened in the West. And the flat temperatures over the last hundred years found in the Central States don't appear to hold either.

Breaking this down to a review of the initial Time of Observation corrected temperatures, but initially again just averaging the state temperatures, one gets:

Average temperature for the states along the West Coast, averaging the TOBS average state temperatures.

In contrast with the Middle States there does appear to be a steady increase, with time, in the average temperature. Looking at the average of all the stations (a total of 138), the data continues to show that rise:

Average temperature for the states along the West Coast, averaging the TOBS average station temperatures.

The area that each station covers falls from an average of 3,000 sq miles in California, through 2,460 in Oregon to 1,621 in Washington. When one adjusts for area, using this weighting, and adding a trend line to see what the temperature change averages, one gets:

Average temperature for the states along the West Coast, weighting the TOBS averages by area.

There is still no sign of that fall in temperatures in the 1950’s, in fact the temperature goes up. Comparing the results for the three different states:

Average individual West Coast TOBS temperatures over time

The form of the plots are roughly similar with the two more northern states showing almost identical patterns, and a slightly wider range of fluctuation.

When one compares the three regions that I have looked at to date, however, the difference between them is quite clear. Well actually, if I plot the data itself it is a little obscured by the curves as they superimpose.

Average temperatures for different regions of the country over the past century.

The Middle states are clearly warmer than those on the two coasts, which I hadn’t expected, but it is more difficult to separate the two coastal variations. Because of this overlap I have moved the lines a little apart, so that the changes in pattern can be more clearly seen. So, for this plot, ignore the temperature values on the left, since I have, as shown, adjusted the values so that they are separated, and so that the differences in behavior each year can be seen.

Pattern of temperature change for three regions of the United States over the past century.

While there is some congruity between the central and Atlantic values, these are clearly different from the Western states. Perhaps I should see what is happening in the mountains??

I am also curious to see what the effects of El Nino’s have on the land temperatures, but I think that I will add in the mountain states, before putting those effects onto the plot.

I might start here but any other suggestions would be welcome.

Two stars for Katla (a volcanic intensity scale)

2011-10-03T22:06:00.007-05:00

Having just finished the post on Eastern Canada, I glanced at the Icelandic Activity Map, on my way to shutting things down for the evening. Katla, the volcano that lies under the Myrdalsjokull glacier has seen a steadily increasing level of earthquake activity over the summer, as I have been noting. This now seems to be picking up a little more with two quakes in the caldera region that have reached a level of 3 or more. (Signified by a star rather than a dot). The younger (green) of the two shown was a 3.3, while the older is reported at 3.0.

Earthquakes in the region of the Katla volcano over the past 24 hours (Icelandic Met Office)

UPDATE: And just as I finish the post on Western US temperatures, and check with Katla, the activity seems to be picking up even more with a 3.9 earthquake sitting on top of the earlier 3.3 (you can see it as a yellow star in the background). But there is also a considerable amount more activity in the caldera, which has to be worrying.

Activity on the evening of the 5-6th October (Icelandic Met Office).

Jon is posting some of the seismic information on the quakes at the Iceland Volcano and Earthquake site, and the Icelandic Met Office has now issued a statement which also shows the unusual nature of the current activity, in that it includes a number of earthquakes above a level 3, and that the activity still appears to be increasing. A more distributed graph of the recent activity can be found here.

OGPSS - Pipelines and Eastern Canada

2011-10-03T21:25:00.007-05:00

I wrote, last time, about the projected pipelines that are being anticipated to take advantage of increased production from the oil sands in Alberta, Canada with the intent that I would use that to lead into a review of the oil sands operation itself. However Gail has raised the issue of the proposed reversal of the pipeline (Line 9) that runs from Sarnia in Ontario to Montreal so that oil would flow to the Suncor refinery in Montreal, rather than the current flow which runs the other way. (Sarnia is right by Detroit). The pipeline reversal is planned to continue beyond Montreal, to include reversing the flow of a supply pipeline from Portland, ME so that the oil from Alberta might also supply northern New England. The project has been called “The Trailbreaker” and had been postponed two years ago when demand declined.

The overall question of the relative role of exports and imports on the Canadian oil supply equation was also raised in comments on the previous post. As a result I am going to look a bit more into the overall Canadian picture, and particularly that in the East Coast, and will postpone the oil sand piece a week (sorry Neil). To begin it helps to look at the current projects that Enbridge have in mind for pipelines.

Overview of the Enbridge planned pipeline projects (Enbridge)

The Ozark pipeline, which is shown running from Cushing to Wood River was closed on Friday, Sept 30th, when the pipeline was found to be exposed as it ran across the bottom of the Mississippi River. It carries around 240 kbd and the shut down is precautionary, since there has been no leak detected.

The dark green arrow from Cushing to Houston will be known as the Wrangler pipeline and would carry up to 800 kbd from Cushing to the refineries along the Gulf, competing with the Keystone XL, which is planned to bring an additional 500 kbd down from Alberta (about 500 kbd flows through existing connections). The intent is to move the oil away from Cushing where it is proving to be a bit of a glut.

With this surplus, and the ability to move oil around the Mid-West, the need for additional feed down from Montreal dissipates, and thus the argument for the reversal of flow so that crude from Alberta can be sent back up that pipe to the refineries in Eastern Canada. At present oil comes by tanker to Portland, ME and then enters the Portland-Montreal Pipe Line (PMPL) system. The oil flows through either an 18-inch or 24-inch line up to Montreal, a distance of 236 miles, with flow then continuing to Sarnia. A certain increase in energy security would thus be achieved for the East Coast of North America, if the oil refined on the East Coast was produced in North America, instead of coming from Russia and the Middle East. At present flow would be reversed in only one of the pipes, the 18-inch, coming from Portland. At present some 200 tankers a year offload in Portland, and send around 95 kbd up to Montreal. (The pipeline came into being in 1941 to avoid exposing oil tankers moving into Quebec to U-boats).

Portland Montreal Pipe Line (Wikipedia)

If one looks at the overall flows of oil in Canada, the increasing reliance on Albertan oil can be appreciated.

Flows of Canadian crude oil in thousand cubic meters/day – (multiply by 6.3 to get kbd) in 2009 (Canadian NEB)

Canadians consume around 1.5 mbd, of which half is gasoline, and 30% diesel. I discussed their exports in the last post.

Interestingly the largest exporter of gasoline from Canada to the US lies further East, where it comes from the Irving Oil refinery in St John New Brunswick with the 300 kbd refinery shipping 75% of the gasoline it produces into the Eastern United States.

There are two other refineries in the region, the Dartmouth refinery at Halifax in Nova Scotia refines 82,000 bd of crude, largely for the Eastern provinces of Canada. The crude is off-loaded from tankers, refined and then loaded onto smaller coastal tankers for delivery.

Yet further East is the Come by Chance refinery, now the North Atlantic Refinery in Newfoundland. In its time it was one of the largest bankruptcies in Canadian history, but it now refines some 115 kbd that arrives in 320,000 ton tankers at the nearby ice-free port. It suffers from that bankruptcy in that a subsequent sale was commensurate on the product not being sold in Canada (outside of Labrador and Newfoundland), which means that the products largely ship to the United States.

Yet one must go even further East to find the oil fields of the Eastern Canada Sedimentary Basin. And unfortunately while the nearest refinery might be near an ice-free port, the fields themselves are not.

Eastern Canadian Sedimentary basins and hydrocarbon fields (Center for Energy )

The fields include White Rose which is expected to yield around 230 milllion barrels, at around 120 kbd, with a life of 12 – 15 years. First oil was in 2005.

Terra Nova is estimated at 406 million barrels. With a production of around 125 kbd it is anticipated to last 18 years. Production began in 2002.

Seasonal floating ice in these parts varies from 1.6 to 5 ft thick and an average wind speed of around 20 mph. also leads to ice buildup on the tankers and superstructure making it a consideration in operations, as are icebergs. (Remember the picture of the tug pulling an iceberg). That was taken around here.

Hibernia is also producing at around 126 kbd, and by August 2010 had produced 704 million of the 1.4 billion potentially recoverable oil from the field, Approval has now been given to extend development to the south.

Current plans to develop Hebron, some 6 miles N of Terra Nova include also the fields of West Ben Nevis, and Ben Nevis. Production is expected to begin in 2017, at a rate of around 150 – 180 kbd of oil and 200 – 350 kbd of water. Reserves are considered to be in the 400 – 700 mb range.

Although these numbers are significant, and will provide for a considerable fraction of the need in this part of the world, and further south, they do not constitute the promise of sustained increased levels of production that are required for significant help against the declining production seen in many of the worlds major oilfields. For some help in that direction it is necessary to head West. And so it is time for the review of the oil sands.

There is however, considerable controversy over the operation of the oil sands in Alberta, particularly from those objecting citing the mess that is made of the landscape. In general the illustrations of oil sand operations that are used, show the site during mining, where the black color of the sand tends to make for a dismal picture. It might be more informative to show what the sites are like afterwards. And so, as a prelude to more discussion, here is a photo of some reclaimed land. It is here that the wood bison (as opposed to buffalo) roam.

Reclaimed land after the oil is removed from the sand (CAPP )