The 2012 version of BP Energy Outlook 2030

There are many unintended consequences as fuel supplies become more scarce, and expensive. (With a h/t to Rune Likvern), I see that those Greeks who are being starved of affordable fuel are starting to chop down trees for warmth and income. This sort of desperation has devastated the countryside all over Albania, Africa and Asia, and is extremely difficult to recover from. To stop that practice spreading the world expects that fuel must be available at an affordable price, and one of the ongoing questions is as to whether it will continue to be.

In that regard BP has just released its Annual Energy Outlook 2030 looking at how the world energy supply, and mix, will change in the years up to 2030. The booklet is an update from the study that it released last year, and which was reviewed at the time. This year the introductory speech by Bob Dudley focused on energy demand in China and India; Middle East exports and transport fuel demand. BP see overall energy demand growing some 40% over the next two decades, with virtually all growth coming from the developing countries. More than half will come from China and India alone. And of that energy, they anticipate that the supply will break out as follows:

Summary of energy supply source contributions (BP Energy Outlook 2030)

Demand will grow across virtually all sections, apart from that of transportation in the OECD, which is expected to fall over the next two decades.

Demand changes in the next two decades (BP Energy Outlook 2030)

Oil will still be the basic source for transportation fuel, and though growth in demand is anticipated to be only 1% a year that turns into another 16 million barrels a day by 2030. One has to be careful therefore in assessing the contributions of the different sources of fuel, as percentages, since, while these may be falling relative to the whole, the actual volumes that are being consumed may still be rising.

Expected changes in the relative sources of energy supply prediction from last year (left) to this (right)through 2030 (BP Energy Outlook 2030)

On a minor note, the role of coal, some 20-years from now surpasses that of oil, while last year the two were about equivalent. Even though BP expect that, by 2020, coal’s share of the global market will begin to fall, though less steeply now than they anticipated last year. And BP expects that some of the change in the mix will be brought about by technical change.

Technology underlies many of the trends apparent in this report. For example, the supply of gas has been accelerated as a result of technologies that unlock shale gas and tight gas. In the transport sector, we believe the efficiency of the internal combustion engine is likely to double over the next 20 years. And that will save roughly a Saudi Arabia’s worth of production. By 2030, we expect hybrids to account for most car sales and roughly 30% of all vehicles on the road.

The interesting question is, of course, where BP think that all the oil will come from. Last year, when they projected the same growth rate, the sources were expected to be Saudi Arabia and Iraq. This year they project that more will come from Deep water, rising from the 9% of supply anticipated last year, to 10% in the current review. (Currently it is at about 7%) But, more interesting is that they see the roles of energy efficiency and technical exploitation of indigenous resources leading to a great change in the international fuel market.

we foresee both the Americas and Eurasia - or Europe including Russia and the former Soviet Union - achieving self-sufficiency in energy, while the Middle East will generate surplus supply for Asia’s surplus demand. In the US for example, oil imports have dropped by about one-third since peaking in 2005 and are likely to be half of today’s level in 2030. The US now produces over 50% of the liquid fuel it uses – as opposed to importing the majority, as was the case a few years ago.

For the U.S. and European pictures to change as much as they anticipate, cellulosic ethanol still appears to be the flag pole on which they have hung their future, and in which they remain heavily invested. Yet when one looks at the make-up of the sources for fuels in 2030, as projected this year over that suggested last there has been a slight gain in overall volumes required.

Anticipated sources of fuel in 2030 – last year’s projection (left) and this year (right)

The interesting changes come in the changes in the Non-OPEC growth, with the contribution from bio-fuels diminishing, growth in US production replacing that anticipated from the FSU (wonder where that went?) and a drop in the Non-OPEC declines. To answer my own question, I suspect that the growth in FSU supplies (which I am covering elsewhere) has been melded into the need to sustain production at current levels, and that may be a part of the reason for the drop in the Non-OPEC declines.

When one considers that BP are forecasting an increase in demand of 8 mbd from China, 3.5 mbd from India, and 4 mbd from the Middle East, with the non-OPEC decline being at 6 mbd, there is a total of 21.5 mbd of new production being forecast, over the next 20 years. And of this 12 mbd will come from OPEC, namely Saudi Arabia and Iraq, but with a significant contribution, 4 mbd, from NGLs.

At which point I cough gently and draw your attention to recent remarks (h/t Stuart Staniford) of the Saudi Oil Minister, who suggested that they have flexibility up to a full production of 12.5 mbd, with a little time, but, on the other hand, they will drop production to keep the price over $100 a barrel. And so there is a suspicion that as Libyan oil production returns to normal, Saudi production may fall, in balance. The upper limit on Saudi Production had earlier been set at 12 mbd, but both these figures are now coming under increasing question, particularly since Aramco has had problems in finding a market for their heavier crudes, which make up almost all of the surplus over current production. (And the Saudi refineries to treat them are still a couple of years away). Yet if the refineries to treat those oils do come on line, and that increases Saudi capability by 1 mbd of marketable product from Manifa, it will still only bring them up to about 11 mbd. And it may be that they will raise production that much, to offset increasing domestic use, and maintain the volume of exports that they need to sustain their economy. But how long they can do that, relying on their ageing major reservoirs remains, of course, the other big question. BP anticipates that they will increase production by 3 mbd over current levels, and still have a cushion of a million or so barrels a day.

And as for Iraq, the country exported 2.14 mbd in December having risen 275 kbd or 14.4% over the year. Whether that can be sustained in the face of continued troubles is not clear. The Al-Ahdab field has come on stream and is ahead of schedule, at 120 kbd, though it may well be that all that oil ends up in China. BP, however, are assuming that Iraq can double production, to 6 mbd, by 2030.

Growth in production in the Americas is anticipated to come from the oil sands (up 2.2 mbd); the Brazilian deep waters ( another 2 mbd) and U.S. shale oil ( at 2.2 mbd). Total biofuels growth of 3.5 mbd balances out the anticipated supply and demand at just under 105 mbd.

The continued growth in natural gas is divided into two parts, that which is shipped through pipelines, and that sent as LNG in tankers. Total demand will rise about 50% with the Middle East, China and India providing most of the increase in demand, and with supply coming from a number of sources.

Changes in natural gas demand and supply over the next 20 years (BP Energy Outlook 2030)

The growth in use will be across all sectors of the economy, but if I do an eyeball comparison it seems as though there is a significant drop in LNG increase over the numbers that BP were using last year. Back then they were seeing an increase of around 70 bcf/day over the interval, now while they are projecting a growth of 4.5% p.a. the overall volume is somewhat less.

Coal demand will continue to rise, largely due to increased demand for power and industrial use in China and India, while western nations slowly ease away from the fuel.

Changes in coal use over the next 20 years. (BP Energy Outlook 2030)

BP summarizes the changes that they have made, relative to last year’s forecast as:

Changes in BP forecasts from 2011 to 2012. (BP Energy Outlook 2030)

Overall it looks to be a rather optimistic view of the future.

OGPSS - The oil in the Western Siberian Basin

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

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

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

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

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

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

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 )