Tech Talk - Here we go again, again

A couple of posts or so ago I mentioned that there are three major problems sitting relatively un-noticed as we head into the mess of Peak Oil. Of these, perhaps the one that gets the least attention is the steady decline in production from existing wells. We are just about at the point where the Alaskan Pipeline will tip over into feeding less than half-a-million barrels a day down from the North Slope. (It sent 501 kbd down the pipe in June with a 98.6% reliability factor). At the same time those in control of the oilfields in the Russia are reporting that Russian exports have fallen to the lowest level in 6 years. This brings back the relatively unrecognized reality of the Export Land Model which Jeffrey Brown first introduced on The Oil Drum back in 2007.

It is worth resurrecting that thinking (which time has proven to be only too true) as we look at the continued declines in production from the UK, as an example. It is not easily discernable from the official Department of Energy and Climate Change, which plots oil production on a monthly basis (with different months having a variety of days):

Figure 1. Monthly production of oil from the fields of the UK continental shelf (DECC ).

Euan Mearns has, however, done the necessary arithmetic and clearly shows the reality of the situation once one converts it back to barrels per day:

Figure 2. UK production of oil and natural gas over the past decade (Euan Mearns)

The steady decline has also been noted by the EIA who commented that UK production fell by 9% from 2012 to 2013. There was a time, back in the days of The Oil Drum, where we debated whether an estimate of 5% for field decline rates was or was not too high. Obviously those days are now behind us, and reality is starting to show numbers that far exceed the rates that, at the time, some thought rather pessimistic. To continue the UK numbers, as OPEC recently anticipated, the decline this year will take the total down to 800 kbd with an 8% decline expected for this year.

The Export Land Model, in its simplest form, can be illustrated with the following plot:

Figure 3. A simplified illustration of the changing production, internal use and exports for an oil producing country, once it reaches a peak in production (Sam Foucher )

The argument that produces the above plot goes along the lines that, as an oil producer (think for a moment of Russia for eg) produces larger volumes of oil, so the economy of that country starts to grow. As that growth continues it demands an increasing amount of energy to sustain the increased internal demand (the green line). However, once production stabilizes or starts to decline (the blue line above) so the amount available for export becomes reduced (the red line).

The three top producers of petroleum products in the world are the United States, Russia and the Kingdom of Saudi Arabia. The United States consumes far more than it produces, and thus is already a net importer of petroleum products, although in the short term, as I noted earlier production gains from the Bakken and Eagle Ford are hiding the problems of decline rate. It is increasingly unlikely that any significant volume of US oil will make it onto the world market.

Saudi Arabia has, for years, controlled the amount of oil that it puts on the market, based on the anticipated global demand, and the supply available from the rest of the world - so that the global price remains at a level to sustain OPEC economies. That has been illustrated over the past couple of years by the increase in production from the KSA to cover the decline from Libya as about a million barrels a day disappeared from the global market. The gains in production from the US helped in meeting global demand and the strain in supply was thus relatively easily hidden. But the KSA has an imminent problem that has largely disappeared from public view now that the eyes of The Oil Drum correspondents have lost that focus.

The major oilfields of the Kingdom are old, and to sustain production perimeter wells were located around the oilfields that injected millions of barrels of seawater a day, to drive the oil towards the center of the fields, where it could be relatively easily recovered from Maximum Reservoir Contact wells drilled along the very top of the reservoirs. But as folk such as JoulesBurn have noted, those wells slowly change in nature, over time, as the oil migration continues, and water injection must move inwards to ensure continued production.

Figure 4. Layout of initial wells at the Haradh III development in the Ghawar oilfield in Saudi Arabia (JoulesBurn at The Oil Drum)

He noted, in the original post, that Aramco had to drill some 52 wells, rather than the estimated 32, to get the production they needed, and that was back in 2010. Since then Ghawar has continued to produce for the Kingdom, but with daily levels of up around 10 mbd, the volumes in the crests of the anticlines along which the oil wells sit within the Ghawar field have been steadily contracting, and although they have carried out some of the most advanced oilwell engineering to sustain production from the attic oil in the older parts of the fields, there are only so many ways you can squeeze a rock before you get out all the oil that you will – and those days are approaching fast.

At the same time (relating back to the ELM) while Saudi production has remained at just under 10 mbd for the past few years, internal demand has been rising at a steadily more rapid rate.

Figure 5. Internal consumption of oil in Saudi Arabia (Index Mundi ).

Hoping to transition some of the current internal demands to natural gas, the KSA has been looking for internal resources to allow it to move away from oil. However the search has not been as successful as hoped, particularly with the search for natural gas, Shell having backed out of the program as a result of the poor results to date.

With internal consumption continuing to rise at more than twice the rate anticipated by the ELM shown in Figure 3, and, at best, stable production, global exports from the Kingdom are of increasing concern.

Which brings us back to Russia, where the new fields that must be exploited to sustain production are in remote parts of Eastern Siberia and the Yamal Peninsula – if not offshore in the Arctic.

Russian oil production has been peaking for some time (falling from 3.4% growth in 2012 to 1.3% in 2013) and is now reported to likely fall by 6.3% over the next two years. Since this implies that Russia is now at peak, the decline in overall production initially will fall below that of Figure 3, though likely only for a year or so, before the rate will be, at minimum, that shown. (The reason for this conclusion comes from the lack of enough investment in the fields where growth can be expected). At the same time internal demand is rising at around 100 kbd or 3% pa slightly above the value assumed for Figure 3.

If none of the three largest producers can even sustain exports, and the ELM explains why they can’t, and world demand continues to rise at the rates projected, then, in even the short-term, something is going to have to give. The logical weakest link is price, with the consequence, that invalidates a lot of the other arguments, of a significant impact on global economic health. As we have seen before, significant increases in price lowers the demand for oil, and thus demand from the various nations will become even more skewed.

The only problem, with this next iteration, is that there isn’t another Bakken or Eagle Ford conveniently sitting waiting to be tapped.

Tech Talk - changes in South American exports

One of the large concerns that came up repeatedly over the years of discussions, both of the articles and of Drumbeat at The Oil Drum (TOD) was the subject of growth in domestic demand from some of the larger suppliers of oil and natural gas. This growth would be to the cost of the export market, and will, therefore, over time, reduce the amount available to importing nations. This becomes an even more painful reality to the rest of the world when the projections about future performance turn out to have been overly ambitious. Consider the countries of Latin America, where, back in 2010, the EIA drew the following baseline:

Figure 1. The largest producers of liquid fuels in South America in 2010 (EIA )

The EIA anticipated that Brazilian production would reach 2.8 mbd in 2012, and 3.0 mbd this year. However, as the latest MOMR from OPEC notes, Brazil will likely produce only 2.61 mbd this year, with the potential to rise to 2.67 mbd by the end of the year. However the rise in domestic consumption, and the failure to achieve the production goals expected has had an impact on the exports to the United States.

Figure 2. The changing volumes of US imports from Brazil (EIA )

The EIA reported that Venezuela produced some 2.47 million barrels a day in 2011, of which the USA imported roughly 1 mbd. That volume has, however, been declining for some time. (Note that in the plot below the Virgin Island imports should perhaps be included, because the crude that runs through the refineries on the islands originates in Venezuela, but they are not in this plot). At the same time a significant proportion (250 kbd in 2010) is now being shipped from Venezuela to China.

Figure 3. The changing picture of US imports from Venezuela over the years (EIA )

The situation in Argentina similarly shows that as with the other countries internal consumption is rising, while in this case overall production is falling and there is a consequent impact on exports.

Figure 4. The oil balance in Argentina (EIA )

China has been getting around 20% of Argentinian exports, while, in 2011, the USA got 40%, but the volumes of US imports have now turned negative.

Figure 5. The changing picture of oil imports to the USA from Argentina (EIA )

Of the five countries that were tabulated at the top of the post, Colombia is the exception. Production is still rising significantly, however it should be noted that, back in 2010 when the USA received some 422 kbd of crude and refined products from the country, China was financing a pipeline to carry 600 kbd to the Colombian Pacific Coast.

Figure 6. The increase in oil production with little increase in domestic production in Colombia (EIA )

The oil for the pipeline is anticipated to come from both Venezuela and Colombia, and the preliminary agreement for its construction was signed in May, 2012. Venezuelan agreement is still lacking to the deal and Venezuela, which was supposed by now to be sending natural gas to Colombia (after having received supplies for years) has still not made the switch. Volumes of exports to the USA from Colombia have fluctuated recently, while India and China have been acquiring oil wells and their production, which then ships to Asia.

Figure 7. The changing picture of oil exports to the USA from Colombia (EIA).

And that leaves Ecuador., which for those who might have forgotten, is also a member of OPEC. (It rejoined in 2007 ) It produces around 500 kbd, and with internal consumption running at around 200 kbd, exports the rest.

Figure 8. The changing picture of oil exports to the USA from Ecuador (EIA )

The recent news that the President of Ecuador is opening the rain forest to oil development, after trying to find funds for preservation of the forest without it and failing. Ecuador has an increasing debt with China (about $20 billion) and this is forcing it to use oil exports as a way of servicing that debt. One $2 billion loan, for example, carries a return agreement for some 130 million barrels of oil over six-years (60 kbd). Part of the loan from China will be spent on refineries in country.

The point to note in all five cases is that the imports to the United States have been declining. Given the increase in US domestic production that is not wholly surprising, nor is there yet any immediate cause for concern. But it is what is happening to whatever excess that these countries produce, over that consumed domestically and in the US that is significant. Because, increasingly it is going to China, and to Asia in general.

The concern that this raises is that, should US production not continue to rise at the rates that the more cornucopian of the main stream commentators suggest, then there will come a time when the US will have to go back to its suppliers from the last decade to ask for more. And at that time the odds are going to be high that either the countries won’t be able to meet the demand because their own domestic consumption has consumed the surplus, or that the surplus has been sold to China.

Given that China is making investments at the moment in the South American oil infrastructure, from wells to pipelines, means that it will control this production, and that removes a significant source of supply, at a time when it will be needed.

OGPSS - Oil producers just below 1 mbd, India, Argentina, Egypt and Oman

There were nine countries that, in 2008, produced between 500 kbd and 1 mbd , according to the EIA. Of these one, Azerbaijan, has been able to increase production to just over 1 mbd, and I wrote about it last week. Let me, therefore look at the first four of the remainder – India, Argentina, Egypt and Oman, in this post. The latter two are part of those countries where popular protests have in one case brought down the government, and in the other caused some changes to be made. How these will play out in terms of oil production, and oil exports remains one of the questions which are currently unanswerable.

India was producing 888 kbd of oil in 2008. It is a country with recognized growing demand for oil, to the point that Libya’s Gadaffi has offered it the chance (along with Russia and China) for them to replace Western companies who have shut down operations because of the turmoil. The growing internal demand for vehicular liquid fuel, remembering that India was the country that introduced the Tata Nano, is reaching record levels. Growth for different sectors of that market are rising at more than 10% a year.

Local car sales jumped 23% from a year earlier in February to 189,008 vehicles, showed data issued Wednesday by the Society of Indian Automobile Manufacturers, an industry lobby group. The figure is more than January's all-time monthly record sales of 184,332 cars.

Indian demand for oil is now more that 2 mbd above domestic production and it is increasingly dependent on imports. In 2009 the EIA showed where these came from:

Source EIA
As one looks at the coming global oil market, therefore, India is one of the BRICS nations (Brazil, Russia, India, China and South Africa) that will drive increased international trade, likely well above the levels of today. The EIA consider that Indian growth will be on the order of 100,000 bd per year, which will likely have to be met by additional imports.

The Indian situation in regard to natural gas is similar. Although production has started to increase signficicantly, demand continues to outstrip it.


In the global market India has often been overbid by China as both seek to guarantee fuel supplies into the future. India is currently seeking to add Russia to its suppliers. and there has been an ongoing effort to run a pipeline down from Turkmenistan into India, via Afghanistan and Pakistan, for a number of years. (The TAPI Pipeline) At the moment agreements are reported to be imminent, and these will be followed by natural gas purchases. It should be remembered, however, that the pipeline has to run through Afghanistan and over its thousand-mile length will pass through Kahdahar Province, and then through the troubled tribal areas of Pakistan.


Route of the planned TAPI pipeline to India.

The pipeline would deliver up to 2 bcf from the rich Turkmen fields, though some of the resulting flow would likely be tapped along the way to help both transmitting countries, before the remainder reaches India.

An alternative would be to run a pipeline from the natural gas fields of Iran down through Pakistan into India. This is the IPI pipeline, but (because of the sanctions on Iran) is less favored, at least by the US. And, unlike China, which has already created the pipelines into Turkmenistan, India is still not that far along in the discussion.

Planned route of the Iran, Pakistan India pipeline

Argentina does not attract a whole lot of attention on the hydrocarbon front page. Yet, the picture of how it illustrates the Export Land Model, can perhaps easily be seen from this plot from the Energy Export Databrowser.

The Argentine oil statistics (Export Energy Databrowser )

The situation in the Argentine is perhaps illustrated best by the actions of Repsol, Spain’s largest oil company.

“The sale of YPF shares is part of Repsol’s strategic goal to rebalance its portfolio of assets,” the company said.

Repsol is seeking to reduce business in maturing fields in Argentina while investing in exploration in Brazil’s offshore Santos Basin and elsewhere to increase output.

Thus, as production in the country falls, and demand rises, the amount that is available for export will likely continue to decline. The EIA, which listed Argentine production at 782 kbd in 2008, anticipates that it will be slightly down at 760 kbd this year continuing the trend shown above. Nevertheless, as Spain pulls out, China is moving in , buying out the Exxon Mobil interests in the country.

The natural gas picture is just a little further along, with production having peaked, domestic consumption which had followed right along, now requires that the country begin to import natural gas.

he Argentine natural gas statistics (Export Energy Databrowser )

It is expected that the natural gas fields in Argentina will collapse fairly quickly, with reports that the country will sensibly run out of the fuel within seven years. Within that time frame it is likely that only the current glut in supply will help. But (as with the UK) as more countries find themselves in this predicament, the supply excess will more rapidly attenuate.

Egypt was, of course, one of the two countries that led off the current popular protests against state leaders that had led too long. Producing 718 kbd in 2008, it was about that time that domestic consumption overtook production. Production in 2010 averaged 660 kbd, of which 540 kbd was crude oil.


Government plans to control demand as the country moves to import a larger percentage of that demand are likely now out of the window, at least in the short term. Because the country has about a million b/d refining capacity it will continue to both export and import hydrocarbons, but with the balance swinging toward the import need, within the frame of the current unrest, it is difficult to predict how this will evolve in the future.

Consider, in this regard, the natural gas exports to Israel and Jordan. Until five weeks ago a pipeline carried the gas across the Sinai . Following a terrorist attack on the pipeline flow has been restored to only a quarter of the previous level, and even that is now in question, as a leak just halted the flow again.

Egypt has been supplying 40% of Israel's natural gas since May 2008 – raw material for the production of 20% of the country's electricity – through the state-owned EMG company, businessmen Hussein Salem of Egypt, Yossi Maiman of Israel and Jewish American Sam Zell, and Thai energy company PTT.

The Egyptian opposition openly objects to the gas deal signed between the two countries in 2005. Since the Egyptian supply was halted, Israel Electric Corp. and the private power plants have been purchasing their gas from the Israeli Yam Tatis reservoir.

Gail has recently written on some of the back story to the Egyptian problems and with the rising population, and their increasing expectations from whatever new government finally evolves, it is likely that demand will continue to grow. However, with a relatively large reserve, Egypt can continue to export into the future, though the customers may be more politically screened.


Finally, for this session, I will refer again to Oman. I wrote about Oman just recently, as the protests in other countries had started to be repeated there. There has not been much of a change in the situation since then. Protests are continuing. Saudi Arabia is now responding more aggressively than earlier, troops having been sent into Bahrain And this, perhaps, implies that reactions will not be as peaceful as they have been to date. In that scenario it is not possible to predict whether even popular monarchies such as that of Oman will survive. That , in turn, calls into question the overall reliability of oil and natural gas supply from the Middle East and North Africa. Given the nervousness about nuclear power, it will be interesting to see how the governments of the world react. There are no easy answers

OGPSS - Some limits to oil fungibility

This is the second in a series I am just starting on oil production and consumption around the world. While it is going to focus more on individual nations and oil fields, over time, there are some general remarks that I want to use to preface the series and this is one of those. (OGPSS – Oil and Gas Production Sunday Series).

One of the first things that I was told when I started looking into whether there was a coming crisis in oil supply was that oil is fungible. What that meant was that if, for the sake of discussion, the Saudi Arabian government cut off oil supply to the West, then the West could turn around and buy an equivalent amount from somewhere else (it turned out to be the North Slope and the North Sea) and the world could continue on its merry way. In fact if you go to Merriam Webster oil is cited as an example of a fungible commodity.

being of such a nature that one part or quantity may be replaced by another equal part or quantity in the satisfaction of an obligation:- oil, wheat and lumber are fungible commodities.

But that assumption is not totally true, and in the world where matching production to demand is becoming a somewhat more difficult and expensive operation the limits to the fungibility of oil may soon become more evident.

One of the reasons for this is that, with some increasingly rare exceptions, one cannot drive up to an oilwell and fill the tank with the flow out of the ground, and then drive happily off. Crude oil is a mixture of different hydrocarbons. (Morgan Downey explains this is more detail in “Oil 101”, and I will refer to that book a number of times as this series progresses, it sits on my desk.) Hydrocarbons are a combination of hydrogen and carbon atoms in different combinations, but with very approximately, twice as many hydrogen atoms as carbon. As the number of carbon atoms increases one moves from the simple light compounds such as methane (CH4) to the more complex heavier fluids that get down to residual oils ( 29 to 70 carbons) and bitumens (above 70). Because the different components of the oil have different uses, the different fractions of the oil are separated out for individual use at a refinery. The quality of the crude is generally expressed by the API gravity, of which more in a later post.

Typical crude oil fractions

Because the different oilfields of the world produce oil with different combinations of hydrocarbon compounds, and with varying levels of other contaminants, such as, for example, sulfur, it is not always easy to switch the oil supply coming into a refinery from one field to that from another. The EIA has plotted the increase in sulfur content coming into US refineries. As the crude becomes heavier and contains higher sulfur content, so the refining process becomes more complex and expensive.


For many years, for example, the heavy, high sulfur, crudes produced in Venezuela were shipped to refineries in the United States that were designed to refine the oil to the desired products. Other refineries, geared to refining lighter sweeter (i.e. lower sulfur) crudes cannot accept very much of the Venezuelan oil and blend it into their process streams, since even to get to an intermediate crude they would need to include a higher quality (and more expensive) lighter crude in the blend. Thus when there was a strike in Venezuela in 2002, and the world lost 3 mbd of oil production, there was only a limited flexibility in the way that the affected refineries in the United States were able to resolve their supply shortfall. (And in those days it was possible to increase Mexican supply to help out).

Venezuela is one of two countries (Canada being the other) with a significant production of synthetic crude from the heavy oil sands in that country. These are a more extreme case of the need for special refineries, since in both the Canadian and Venezuelan case the heavy oil must first be treated at the site to upgrade it to the quality of a conventional crude, before it can be sent to a conventional refinery. (I briefly discusses that refining in an earlier Tech Talk). This established a secondary limit on how much oil can be produced from those deposits at one time. Some time ago I visited the Oil Sand operations in Alberta, and was there on the day that the new Upgrader facility was shut down because of the escape of some of the gases from the process. I could smell a faint odor of “cat pee”, but nothing near the smells from many other processing plants of varying nature that I have visited over the decades. Nevertheless the new section of the plant was shut down for months until the problem was solved, removing over 100,000 bd from the market.

More recently the difference in price between heavy crude and light has reduced, to the point that the Canadians are no longer going to increase the size of the upgraders in the Fort McMurray area, but will instead be shipping the bitumen to eager customers. This does require some additional technology:

Under the new timeline, which was disclosed yesterday, Syncrude will lift production to 425,000 barrels through debottlenecking, and add a further 115,000 per day of bitumen production. Both expansions are expected by 2020.

(With additions to its mining operations, Syncrude actually plans to extract 600,000 barrels a day of bitumen by 2020, but barrels that go through its upgrading process actually shrink in size, resulting in a total output of 540,000.) Bitumen on its own is too thick to flow through a pipeline: at room temperature, it has the consistency of old molasses. But Syncrude plans to employ a new system that uses a solvent to remove what Ms. Fisekci called the "nasty" part of the bitumen. That system, which Syncrude operator Imperial Oil also intends to use at its Kearl oil sands mine, will allow the bitumen to flow without needing to be upgraded.

This will reduce the current bottleneck in production, which lies with the upgrader capacity, since it is only after the crude has passed through them, that it is able to flow easily through the pipelines to the conventional refineries. That change is not yet being considered in Venezuela, where the syncrude is now counted, by the EIA at least, as part of overall production.


The graph from the EIA highlights another consideration as I move to discuss the global trade in oil. That is the rising consumption within the country, a phenomenon that Jeffrey Brown (Westexas) introduced us to as the Export Land Model back in January 2006, since, with declining production it accelerates the reduction in net exports, as the Venezuelan case now illustrates.

I’ll close today with one last point on the limits of fungibility. There are certain oilfields where the contamination of the crude is such that special refineries are needed to process the oil. The most outstanding of these is the oilfield at Manifa in Saudi Arabia, a subject I have been writing about for over five years. The problem with that production, which was initially slated to be in production next year comes from the need for special refineries to process the oil (an extreme case of the earlier condition I described). The plan was that two refineries would be built in Saudi Arabia to handle the initially 1 mbd of planned production, which by last March had dropped to 900,000 bd. One of these is being built by Total at Jubail, though it is interesting to note that the refinery is now scheduled – in its 400,000 bd capacity – to also receive oil from the more conventional field at Safaniya. It is now anticipated to open in 2013. A second refinery at Yanbu will also take 400,000 bd. Aramco will then build a new refinery at Jazan, with a capacity of 400,000 bd starting in 2013. But until those refineries come on line, unless the Saudi’s and Chinese work out a deal (not beyond the bounds of possibility) that oil will stay in the ground.

The above is intended to show is that there are constraints outside of just having oil in the ground, and a ready customer, that preclude immediate sales and satisfaction. As this series develops I will be highlighting some others.