Tech Talk - Rig Counts in the Middle East

In recent posts about the situation in the Middle East, I have noted the need for Aramco to increase the number of drilling rigs that it must use, since it is now looking for natural gas in their tight sand deposits rather than finding the large reserves that they had hoped in the shale reservoirs. It is interesting in this regard to plot the number of rigs that have been working in the Middle East.

Getting the overall data from Baker Hughes the rig count can be plotted, over time, to give the following:

Figure 1. Rig Counts in the Middle East (Baker Hughes)

If one looks at the trend for the last twelve months, it has remains on a fairly consistent upward trend, following that of the longer time interval plot of Figure 1.

Figure 2. Recent trend in Middle East Rig count (Baker Hughes)

Back in the days of The Oil Drum, Euan Mearns and I had this concern, which occasionally surfaced, about these numbers. From my early post on the subject which noted that back in 2005 the KSA were running around 20 rigs, which would not be enough to get them the production they were claiming to need in the future, to Euan’s in 2011, the topic was revisited regularly over the time that the count steadily mounted as the Kingdom had to drill an increasing number of wells just to keep production at around the same overall level.

I am using the KSA as the example, given the large volume of its production relative to that of the others in the Middle East, but as the numbers show, the trend toward increased drilling rate to create enough productive wells to sustain production as the larger volume wells dry up is starting to become a steadily more frantic race across the region.

Rune Likvern used the phrase “Red Queen” in discussing the overall long-term need of the companies in the Bakken to have to drill an increasing number of wells, with individually reducing production, in order to remain in place with regard to overall production. As the production from the Bakken now exceeds a million barrels a day it may seem foolish to be predicting this “squirrel cage” view of the future, but the rig count up there is still running at around 190 rigs, which is not enough to sustain future growth for long, given that access to the sweet spots is limited, and they are beginning to run out of new sites.

So it is in the Middle East. The rig count numbers are mounting steadily, it is reported that there were 88 rigs drilling in the country in October 2012. Last year this rose to 170, and the number is expected to rise to 210 by the end of this year.

Aramco have done remarkably well, over the past decade, in developing new technologies to harvest the attic oil left around the tops of the major producing formations such as Ghawar, as the main body of the fields begin to be exhausted. But the problem with these secondary rig operations is that they were directed at the smaller pools around the field, rather than tapping into the major volume, and thus they had an expected and finite life. That life is starting to come to a close. Just as, when sucking a thick milk shake through a single immovable straw, when it stops drawing fluid, there is still a fair amount left in the cup. But as you move the straw around and slide it up and down the sides, the amount that you recover gets less, and it takes greater and greater effort to get it, to the point where you quit and discard the carton. And that is where the Middle Eastern oilfields are beginning to find themselves.

The high-quality light oils of the mainland are rapidly running out, and the remaining fields with the promise for sustaining Saudi production at around 10 mbd for the next few years, are the heavier sour crudes from the offshore fields such as Safaniya and Manifa. At the same time there is a need to reduce the increasing amount of oil (now at 3 mbd) being consumed in country, with the hope that this can be replaced by domestic natural gas. But those hopes are being reduced as the shales are found to be less productive than anticipated, and hopes are now switching to the slower production that can, hopefully, be achieved from the tight sands – but at the cost of an increased number of wells, inter alia.

This is the writing on the wall for global oil production, and in the short-term it will be neglected. Increasing the number of rigs will, in that interval, increase the number of wells that will produce, even though the volume from each well will be less, and the overall life of the wells will similarly reduce, as higher production techniques tap into smaller fields.

But we are now on the treadmill in the squirrel cage, or, as Rune would have it, we have wrapped ourselves in the cape and crown of the Red Queen, and must run faster and faster just to stay in place. (There are additional concerns since, as an example, Manifa could not be brought on line until there were refineries built that could process that crude, and so the options for increasing production beyond the capacity of refineries to absorb that increase is a futile exercise).

There will soon come a time when the gain from the overall increase in new wells will not match the decline in production from older wells, particularly if the effort to “run faster” is restricted to only a few players (Russia for example is not yet putting the effort and investment into increased drilling rates in order to sustain their overall levels of production, and given the age of their major fields are likely now in terminal decline).

Ouch!

Tech Talk - Oil Supply, Oil Prices and the Kingdom of Saudi Arabia

From the time that The Oil Drum first began, and through the years up to the Recession of 2008-9 there was an increase in the price of oil, and that resumed following the initial period of that recession, and, in contrast to the price of natural gas, oil has recovered a lot of the price that it lost.

Figure 1. Comparable price of oil from 1946 (Inflation data)

And if one were to draw a straight line on that graph from the low point in 1999 though now there hasn’t been a huge variation away from the slope of that line for long. That, of course, does not stop folk from pointing to the very short, roughly flat, bit at the end and saying that oil prices are going to remain at that level, or are even about to decline.

To address that final point first, I would suggest that those making such a foolish prediction should go away and read the OPEC Monthly Oil Market Reports. Remember that, for just a little while longer, oil is a fungible product. OPEC make no secret of the fact that they continuously examine the global economy and make estimates on how it is going to behave. This month they note that the economies aren’t doing quite as well as expected, and have revised down global growth to 2.9%, though they expect next year to be better, and hold to their estimate of a 3.5% growth rate.

But OPEC go beyond just making that prediction, they use it, and data that they have on consumption and oil supplies around the world, to estimate how much OPEC should produce each month to balance supply against demand, so that the price will remain at a comfortable level for the OPEC economies. And based on those numbers they tailor production.

This month, for example, they note that global oil demand is anticipated to grow by 0.8 mbd this year (and by 1.04 mbd in 2014). They anticipate growth in production of around 1.0 mbd from the non-OPEC nations, with projected increases from Canada, the United States, Brazil, the Sudans and Kazakhstan contributing to an additional 1.1 mbd next year. From these numbers they can project that demand for OPEC oil will be slightly down this year, at 29.9 mbd down 0.4 mbd on last year, with next year seeing an additional fall of 0.3 mbd on average.

Figure 2. Projected oil demand for 2013 (OPEC MOMR )

Thus slight reductions in production from OPEC, and particularly the Kingdom of Saudi Arabia, (KSA) can keep the world supply in balance with demand and more critically for them keep the price up at a level that they are comfortable with. Note that in relation to the overall volumes of oil being traded they are not talking much adjustment in their overall volume (around 1% of the total 30 mbd) in order to sustain prices. The USA produces more, OPEC produces less – not much less because global demand is growing – and the price is sustained.

This has virtually nothing to do with the speculators on Wall Street and the corrections they might impose, this is all about supplying a needed volume to meet a demand and controlling that supply to ensure that the price is sustained.

There are a number of caveats to this simplified explanation, one being the short-term willingness and ability of some producers to keep to their targets. One of the imponderables is the production from Iraq. Although Iraq has been given a waiver through 2014 on the need to limit their production, the increasing violence has led to a drop in production, back below 3 mbd.

Figure 3. OPEC production based on data from secondary sources (OPEC MOMR)

As I have noted in the past, OPEC is sufficiently suspicious of the reported numbers from the countries themselves that they check from secondary sources, and provide both sets of numbers.

Figure 4. OPEC production numbers from the originating countries. (OPEC MOMR August 2013)

Note, for example, that Iran says that it is producing over 1 mbd more than other sources report, and Venezuela is around 400 kbd light. The balancing act is largely the charge of KSA, since it produces the largest amount and can adjust more readily to balance the need.

One of the other caveats is that the internal demand in these countries is rising, and that lowers the amount that can be exported. This will in time require that OPEC produce more, just to sustain the amounts that they export. And the problem here is the biggest caveat of all. Because KSA cannot continue to produce ever increasing amounts of oil.

Just exactly how much the country can produce is the subject of much debate, and has been at The Oil Drum since its inception. But if I can now gently admonish those who think it can keep increasing forever, and that it has vast reserves that can flood the market at need. This fails to recognize that the major fields on which the country has relied are no longer capable of their historic production levels, and that, over the time that TOD has been in existence, production has switched to the new fields that KSA had promised it would, back in time.

But these new fields, including Manifa and Safaniya produce a heavier crude that, for years, KSA struggled, usually in vain, to find a market for internationally. It is only now that it is building its own refineries to process the oil that it can find a global market for the product. Yet those refineries have only a limited capacity. If you can’t ship, refine and market your product in the form that the customer needs, it can’t be sold, regardless of how much, instantaneously, you can pump out of the ground. And so KSA is starting to look harder for other fields. They have increased the number of rigs employed to 170 by the end of the year (in 2005 they had about 20 oil and 10 gas rigs operating), going beyond the 160 estimated earlier, seeking both to raise production from existing fields, but also to find new ones. This is almost double the number that Euan reported at the end of last year. That this is being expedited is not good news! Because new fields will very likely be smaller, and more rapidly exhausted, and may not have the quality of the oil produced from Ghawar and the other old faithfuls.

Realistically, over a couple of years, I would suspect that the oil price line, that I mentioned was rising at the beginning of the piece will continue to rise and we are just going to have to accommodate to it.

To Forbes - A Gentle Cough of Correction at TOD's end

Forbes recently issued a commentary on the closing of The Oil Drum, which deserves some rebuttal, since, as with many stories on the "Peak Oil" topic, it conveys too many incorrect statements and false assumptions.

Just over eight years ago I became irritated by several articles in the Main Stream Media that were clearly technically wrong. (My academic research includes many years of making holes in geological media, an interest that began with my doctoral work in the late 1960’s). I began writing about some of the misconceptions in regard to the approach of Peak Oil in a blog I was writing at the time. Shortly thereafter I agreed to join with Kyle, who was then writing his own blog, under the nom de plume of Prof Goose, to jointly create the website The Oil Drum.

In the beginning, Kyle handled the site management issues (a task he later passed on), and my main contribution has been the intended one of writing on the more technical sides of the situation. This was particularly the case during the events surrounding the Deepwater Horizon disaster, where readership of TOD rose to around 60,000 a day. But writing to a site that began to achieve some technical credibility had its drawbacks. Very early on I got into the habit of referencing almost every fact I cited, given the questions that arose whenever I appeared (at least to my audience, but also, at times, in fact) to misspeak. Working for the site has made me a better writer, but it was clear almost from the start that the two of us could not sustain the interest that the site very quickly drew.

Over the years I felt very fortunate that Kyle went out and found funding, and innocents willing to carry the burden of editing the increasingly large talent of folk that were kind enough to contribute to the large interest that the site engendered. The site was fortunate to attract some really perceptive folk, and if I hesitate to name them it is only from the fear of missing the odd one and causing offence to people that I have acquired great respect for over the years. Many of those now have their own sites, and so TOD acted in some small way as an encouragement for that effort and to broaden and grow the community that is concerned about the coming point where the production of oil, at a reasonable price, will be unable to keep up with demand and the unpleasant consequences that will then arrive.

I was watching the hearing before the UK House of Commons Science and Technology Committee this past Wednesday on the public understanding of climate. In response to a question, Ralph Lee of Factual, Channel 4 and David Jordan, Director of Editorial Policy and Standards for the BBC pointed out the difficulty in sustaining the level of stories on Climate Change, because of the need for these to generate significant new material to justify publication. They noted that repetition of the basic information, beyond a certain point, was counter-productive. So it is with the Peak Oil story. The facts, in neither case, change, but the amount of new information while accumulating (vide the superb work that Leanan has done with Drumbeat over the years) is often repetitive or confirmatory of earlier stories and thus harder to turn into interesting and exciting new material. There are developing stories that justify continued interest in the topic, but the slow pace with which some of the stories unfold make it difficult to sustain interest.

The transition of Egypt to an importing state for example, revealed in the Energy Export Databrowser figure shown a few weeks ago illustrates a growing problem that their new government must address, but it can only be covered a few times before interest wanes.

Figure 1. Change in oil consumption and the need for more imports for Egypt (Energy Export Databrowser)

And this holds true for many of the topics covered in the past years. The perceptive articles written at TOD on Saudi Arabia by Stuart Staniford (who now writes Early Warning), Euan Mearns and with JoulesBurn’s images from the satellites showed how Ghawar was in significant decline. But there are only so many photos of oil rig sites in the desert that can be made interesting. Aramco are switching to the heavier oils offshore. Manifa has just started new production and Safaniya is being expanded. These are needed to offset the permanent declines in production from the older fields, but again, other than chronicling these steps it is hard to sustain interest in an inexorable process that takes years to play out and where the route to Peak Oil is following along many of the predicted lines.

Even drawing back the curtains of hype over the Bakken and Eagle Ford production, which Rune and Art have so ably done, can only be written about at a certain low frequency before folk see it as repetitious.

Much of the story of the future supply will, in my view, come from activity outside the United States. There will always be a need to update activities in and offshore Alaska, and in the US shales and other formations where future production will have to come from, but as we are likely to see by the end of this year, the gilt on that gingerbread is very thin. Thus the posts that I have been writing recently (and which will continue on Bit Tooth Energy – my own home site) will likely focus on the situations abroad, such as the Middle East, where the political upheaval has a much greater potential to disturb overall global supply than the changes in the US. Similarly Japan is moving toward a more militant attitude as China moves to extract fuel from disputed fields in the East China Sea. This however, again, is a potential tragedy unfolding in slow motion.

At the beginning of the year the EIA were predicting that gas prices would fall this year and pundits that suggested that gas prices would stay down after the recession still appear with regularity to quote their lines of optimism, even as gas prices stay stubbornly high and potentially may rise through the rest of the year. Why is that? Well the OPEC nations need a certain level of income and adjust their production each month to help sustain prices – something these optimists seem unwilling to recognize.

The problem, however, is that if global demand rises at (for the sake of discussion) 1 mbd a year, then a point will be reached, fairly soon when increasingly this OPEC supply becomes no longer capable of filling the demand. Prices will then rise again, balancing supply against those able to pay for their demand at that price. Stating that this is not going to happen because "a way will be found" is to remain an ostrich.

No, gentle readers, the closing of TOD is, in my opinion, based on a deliberate but IMHO faulty management decision made in that group a couple of years ago. It was predictable at that time, but it has nothing to do with the coming of Peak Oil, and is not even symptomatic of much of a delay in that arrival.

And with that off my chest I will return to writing about the evolving problems. My hope at the founding of TOD was that it would chronicle the events through the Peak, it got to nearly the Peak, though I don’t anticipate that this will be a pleasant story beyond that point. But, that coverage will now shift to being only at a new location at a time chosen by the TOD editors.

OGPSS - Saudi Arabian production - then and now

The latest OPEC Monthly Oil Market Report (MOMR) foresees that demand for OPEC crude oil will decline over the next year by about 300 kbd. This is largely in anticipation of additional production from elsewhere:

Non-OPEC supply is forecast to increase by 0.7 mb/d in 2012, supported by the anticipated growth from North America, Latin America, and FSU. In 2013, non-OPEC oil supply is expected to grow by 0.9 mb/d. The US, Canada, Brazil, Kazakhstan, and Colombia are expected to be the main contributors to supply growth, while Norway, Mexico, and the UK are seen experiencing the largest declines. OPEC NGLs and non-conventional oils are seen averaging 5.9 mb/d in 2013, indicating an increase of 0.2 mb/d over this year.

Overall OPEC sees demand staying below 90 mbd over the remainder of this year, with total growth in demand lying at 1.01 mbd.

Figure 1. OPEC forecast for global demand for the rest of the year (July MOMR )

Much has happened since the late Matt Simmons and Nansen Saleri got together to debate scenario’s for future oil production in Washington, back in February, 2004. While Matt had developed his research that then led into the publication of “Twilight in the Desert”, this was the meeting where Aramco pushed back to explain that there would not be a global problem, for at least fifty years. As this series of posts on Saudi Arabia comes to a conclusion, and moves on to other countries, it is perhaps of some value to look back on the presentation by Mahmoud Abdul Baqi and Hansen Saleri to remember what was said. Back in those days oil demand was expected to steadily rise, with increasing rate, to reach 100 mbd in 2015.

Figure 2. Aramco estimate of demand from 2000 to 2020 (Baqi and Saleri)

At the time Aramco had no concern over the industry being able to meet this increase in demand, and fully expected that Aramco itself would be able to more than sustain its share of the increased demand. They had 9 seismic crews out surveying the country, and some 48 rigs drilling both to sustain their then current level of production, and also to explore for new resources.

Figure 3. Location of exploration wells in Saudi Arabia in 2004 (Baqi and Saleri)

At the time Aramco reported that with 700 billion barrels of oil initially in place, that had been already discovered in the country, they expected to find another 200 billion barrels. Of that discovered oil they considered 260 billion barrels as their reserve, of which, by 2004, they had 131 billion barrels in development. (Note that they defined the reserve as the total amount of extractable oil, not the amount left to recover, they have done that in later computations also, and the latest annual report uses 259.7 billion barrels as that discovered reserve). The Annual Report notes that they discovered one new field in 2011, the Wedyan-1 well in the Empty Quarter flowed at 2.3 kbd from the Mishraf reservoir, while they drilled 161 exploration and development wells.

Figure 4. Amount of Saudi oil that had been developed by 2004 (Baqi and Saleri)

For a short arithmetic problem consider that 260 less 131 equals 129, and it one adds another 21, as a percentage of the 200 billion barrels to be found, then one gets 150 billion barrels. Divide this by 3 billion barrels a year of rough annual production and you get the 50 years of remaining life, that Saudi Arabia considered, back then, that their oilfields have left.

And this is the interesting plot, for it shows what Aramco define as their depletion rate, which is annual reduction of the initial proved reserve. The relevant term is the annual depletion rate:

Figure 5. Annual depletion rates for Saudi and other reserves (Baqi and Saleri)

This should be read in conjunction with the state of depletion of the different reservoirs in the KSA, as reported for 2004.

Figure 6. State of field depletion in Saudi Arabia as reported in 2004 (Baqi and Saleri)

And remember that this was eight years ago, so there has been that much change in the numbers! Aramco also expects to recover about 75% of the Original Oil in Place (OOIP) in all fields. They have been able to reach around that level with Abqaiq, which also suggests that the days of that field are now very numbered. But whether this will be possible in the other reservoirs is more open to doubt, and if there is less recoverable oil, then the actual depletion rates go higher.

But where the field is just starting, such as the new development of Haradh, if they hold the extraction rate to 1.7% of the anticipated total recovery then they anticipate that the field will continue to yield 300 kbd for decades.

Figure 7. Future production anticipated for Haradh III (Baqi and Saleri)

It was this anticipation of success across their endeavours that led the company to project that they would be able to hold a Maximum Sustainable Capacity of 10 mbd until 2042, with it only then becoming necessary to replace reserves from the probable and possible fields yet to be found and developed).

The last few posts have described how, as declining output has now hit the original fields, Aramco has moved to add production from other fields (Shaybah for example will soon be producing at up to 1 mbd) and is introducing multiphase pumps to Haradh and Shaybah to improve production from marginal wells, and in Safaniya to sustain a maximum production capacity of 1.3 mbd. Production from Manifa is also anticipated to step in to cover declines in other fields, and come on line in 2014, with a capacity of 900 kbd.

But these new additions are required to offset the decline in existing fields, which have been somewhat protected from the severity of declining well production by the switch from vertical to maximum reservoir contact (MRC) wells. Although this conceals the depletion of the oil in the reservoir during normal production it does not, by itself, improve the ultimate production from the field, but rather can shorten field life, since these wells have proved to be more productive in rate. Nansen Saleri now appears to duck questions which ask if KSA can increase production beyond 10 mbd.

Within The Oil Drum (TOD) there has been considerable discussion over the rate at which well production declines, and the remaining reserve in the field depletes. One impact of the shift in wells from old established fields is that production from the average well will decline over time, a subject that Euan has visited in the past.

Figure 8. Individual oil well production values for Aramco (Euan Mearns)

It should be noted that the use of the submersible pumps are reported to have brought wells back to around 3,000 bd. But the move over to horizontal and MRC wells has slowed the impact of other changes in the country.

Nevertheless, after putting all this together, I re-iterate my conclusion from last time in that I doubt that KSA will increase production much above 10 mbd, (in June it was producing 9.888 or 10.103 mbd depending on source, and with the rising internal demands (domestic use in the Middle East is now projected to average 7.7 mbd in 2012) world markets will get tighter in the shorter, rather than the longer term.

OGPPS - Saudi Arabia and what lies ahead

Saudi Aramco has stated that it designs the well layouts and extraction patterns from its oil fields so that they effectively decline at a rate of 2% per year.* If one divides 100 by 2 it yields 50. If one subtracts 50 from 2012, one gets the year 1962. Even to those with poor math skills, these are not difficult operations, and they lead to the conclusion that those fields that came into production in the early 1960’s and earlier are now reaching the end of their productive lives. They are not there yet, since production took time to ramp up, and some fields have been rested over the years, when production was cut back, or even mothballed. But it gives you some perspective on the overall scope of the situation, without the need for complex mathematical modeling.

Figure 1. Table of oil fields in KSA and their start dates

(* The IEA apparently believes that the figure is closer to 3.5%) (H/t Matt) Saudi Arabia states that, without using advanced recovery techniques and “maintain potential” drilling sites – often not in the same field as that being depleted – the rate would be 8%.(h/t Darwinian ).

In earlier production practices, where companies “stepped out” production wells away from the original producers, and in this way gradually extended the knowledge of the size of the field, reserve growth over time was a normal development. However, with the large size of the fields in Saudi Arabia, and the need to maintain operational pressure during production, Aramco (as JoulesBurn has clearly shown) rings their fields with water injection wells that drive oil to the central high point of the reservoir and slowly migrates the producing and injection wells towards that center as the field is drawn down. This practice precludes the incremental increase in reserves over time, since the field boundaries are constrained and as the wells reach the central part of the reservoir (the crest of the anticline) a clear definition of the closing days of the field becomes more evident.

At the same time it is worth pointing out that until fairly recently when Aramco were carrying out their “maintain potential” drilling they were merely drilling additional wells at 1 km spacing further down the reservoir. But when one moves from the perimeter of the reservoir to the crest, then there are no more places within that reservoir to continue the practice. Thus, in more recent years Aramco have offset declines in older reservoirs by bringing new fields into production. But, as the illustration below that JoulesBurn has provided for Haradh 3 shows, in the smaller reservoirs it is no longer possible to have the space for multi-year progressions of the wells across the field and thus, to sustain production new fields will have to be added to the network at more frequent intervals to sustain levels of production.

  

Figure 2. Planned well layout in Haradh III (from Aramco via JoulesBurn

Saudi reservoirs have also been large. This brings with it the need for large infrastructure to be in place not only to remove the oil, but also to separate the oil, gas and water (and occasional sand) that come out of the well, and to inject water into the reservoir to replace the oil and maintain the reservoir pressure that drives the fluid to the well. That infrastructure is tied to specific design flow rates and it is difficult to change the volume flow rates by significant amounts at short notice. Thus when a field, such as Abu Sa’fah, for example, is brought on line to produce 300 kbd, the plant is all designed for that flow and there is no immediate way to handle an increase in flow. Aramco can only, therefore produce, to the capacity of the infrastructure in place. It is this requirement and “step-function” nature of the additions to oil flow that provides some of the shape to the flow of oil in the region.

However, it is also a limitation, in that the two remaining large sources of crude oil that Saudi Arabia anticipates coming on line must wait until all the logistical handling is in place.

The first of these is the Shaybah expansion. Shaybah began with a production of 250 kbd, and has seen this progressively increased, first to 500 kbd, and then, in 2009, to 750 kbd.. The expansion requires that additional plant be installed to process the hydrocarbons produced which will include 264 kbd of NGL. The anticipated completion date is in 2014.

Manifa has been the more controversial of the fields in Saudi Arabia for some time. Although it has been known to exist for a long time (see above table) and was initially brought into production in 1964, it has never seen the major thrust to develop production that is now underway. There have been several reasons for this, the primary one being that KSA has never needed the production in the past to be able to meet anticipated demand. However there have also been significant questions as to the make-up of the oil, and its need for special treatment. In 2005 it was producing at around 50 kbd, back in the days when KSA was admitting to a decline rate of 6%. JoulesBurn has written about the controversy over the make-up of the oil, which is a heavy, sour crude containing vanadium. Regardless of the validity of those arguments, it does appear that the oil is now going to be fed, as it is produced, to two new refineries that have been planned in the Kingdom. These are at Jubail which is expected to be completed in 2013, and will handle 400 kbd of oil, and the second at Yanbu which, as of this year is being developed with Sinopec, ConocoPhilips having pulled out of the deal. That, together, comprises some 800 kbd of the 900 kbd of oil that Manifa is being developed to produce.

It is pertinent, relative to the opening comment, to note that this is the last large project that Saudi Aramco has reported to be on their books. If one were to accept that their real decline rate is some 3.5% then, at a production level of roughly 10 mbd a year, this would be reducing at 350 kbd per year. A 1.2 mbd addition to current production (Manifa and Shaybah combined) would thus only match just over three years of such a decline rate. For there to be new sources of production brought on line in the future, there must first be a considerable infrastructure put in place, and there does not, at present, appear to be any evidence of this, nor planning and bid documents being prepared for such an eventuality. Remember that Aramco began construction for Manifa in 2007, and it is still likely at least a year from major production.

To some extent this can be overcome by feeding new production from fields not now in production into the existing GOSPs and related facilities. But what that implies is that production will not grow beyond its current levels, which is around 10 mbd. Aramco have become very skilled at controlling water floods, enhancing production from existing reservoirs, and previously bypassed oil, but those wells can only be revisited a limited number of times. Because of the large number of highly productive wells that the country has, it is possible in the short term to raise production but that increase has to go through production facilities which are of only limited volume. Thus the increase can be of only a short duration, and as has been commented by others in the past few weeks, a system cannot be run at full production for long without problems developing. Further the underlying assumption that production declines can be offset by new production to hold depletion to 2% a year is really only true for the country as a whole, and individual decline rates for specific reservoirs have been reported to run between 6 and 8%. As there are become fewer large projects to provide the offset for such decline rates, then the impact of the greater values will become more evident. And so while I expect that the Kingdom will reclaim its position as leading oil producer before long, I continue to believe it will be because of a drop in Russian production, rather than a gain in that from the Kingdom.

OGPSS - Saudi Arabia - production from Safaniya

In recent posts I have been looking at the potential for the historically high producing Saudi oilfields at Abqaiq, Berri and Ghawar to increase, or even sustain current levels of production into the future. This is particularly important when one considers the historic main oilfields in production within that country. And of these the largest not yet covered is the offshore field at Safaniya, today's topic.

 Because of the change in well design, so that long horizontal wells, many with a number of lateral feeds, known collectively as Maximum Reservoir Contact (MRC) wells, located within the top 5 ft of the reservoir are now used, initial declines in production in the major fields have largely stopped. This is partially explained because as a vertical well through an oil reservoir sees the pool getting smaller, the length of well productively exposed to the oil in the reservoir reduces, and so there is a steady reduction in well performance over the years. Where the oil is, however, being pushed up to the horizontal well by an under-flood of injected water (which sustains the differential pressure between the fluid in the rock and the well bore) then the exposed length, and the driving pressure both remain relatively constant, and production is sustained at closer to a constant level until the water flood reaches the well, when the well dies.

 Aramco have changed the design of their MRC wells so that the arrival of water at one location along a lateral is no longer sufficient to kill the well. Installed valves isolate the region of the well where the water enters, and the rest of the well can remain in production. But it will produce at a reduced rate, and is an early warning that the water levels are nearing the well location, and that, before long, the well will no longer be able to sustain the x,000 bd production which has been the characteristic of most Saudi wells for over five decades. This is not to decry the efforts that have been made to recover residual oil left in those fields. As I have noted Aramco have been diligent in seeking to find additional ways to extract the oil that has been left as the waterfloods progressed through their senior fields. But they are also smart enough to know that alternate fields would have to be developed, and brought on line as the limits in the older fields are reached, as they now have been, in some cases for years. There is an interesting feature to the sources of production, back in 1994.
 
Figure 1 Saudi oil production, by field, in1994 (Matt Simmons, “Twilight in the Desert”)
   
Figure 2. Oilfields in Saudi Arabia (from Aramco via energy-pedia 


 The immediately obvious characteristic is that they are, at least to some degree (as with Berri) land-based. (Other less obvious differences are a change in the host rock and the quality of the oil). The most significant of the remaining four is Safaniya which came on line in 1951. But it was not, immediately, produced.

Aramco, in accordance with the terms of its concession, went ahead with the careful development of the field. Between 1951 and 1954, 17 wells were drilled, but they were not produced. . . . . . When it was first put in production in 1957, it flowed 50,000 barrels of crude oil a day from 18 wells. At the beginning of 1962 it possessed the facilities to handle 350,000 barrels a day (almost 128 million barrels a year) from 25 wells.

It was found to be the world’s largest offshore oilfield, and Matt Simmons has conjectured (in Twilight in the Desert) that it is connected to Khafji and through that field into Burgan. When Saudi oil production peaked in 1980/81 he notes that it was producing at over 1.5 mbd. Since then production fell to around 600 kbd, but then has increased back to 900 kbd with plans now afoot to bring it back up to full volume of earlier levels of production, which will require additional forms of artificial lift this being the electrical submersible pumps that have already been introduced into Ghawar. 


 The phase 1 upgrade at Safaniya is anticipated to be completed by next year. The oil is found in sandstone, rather than the carbonates at Ghawar, and in the original development Matt has noted that the weak nature of the sand was causing the wells to collapse as the oil was removed, and that the flow of water into the reservoirs was bypassing a lot of the oil being left in place. As other fields have been developed, they have largely been brought into production fairly quickly. This has not been the case at Safaniya, which as Matt noted:

. . .holds the entire remaining spare daily oil supply of any magnitude . .

In the sense that other fields and opportunities take a little time to bring on line this remains true.

 Manifa, for example, will only start to bring in significant production as the refineries to accept the oil are themselves brought on line in the years ahead. Yet it is still counted as part of the total volume that KSA can bring to the market. Safaniya had, however, been integrated with secondary development of the nearby fields of Marjan and Zuluft into a Northern Area Producing Region (NAPR) back in 1995 and there are enough wells and Gas Oil Separation Plants available, to be able to handle flows of up to 2 mbd. Because, however, the oil produced is Heavy (relative to the Arab Light classification of the production from the land-based reservoirs initially) Aramco also found it sometimes more difficult to market, though that demand also fluctuates. And it has been this marketing problem that sometimes seems to produce the headlines when Aramco sees a world that is increasingly demanding more oil, but has not always been willing to use this heavier supply as an immediate fill-in for existing shortages. (It could not, for example, provide an immediate replacement for Libyan oil last year, even though it was available). As a result the heavier oil is discounted against other Saudi oil. 

 At present the major effort offshore is going toward development of Manifa, which will ultimately bring an additional 900 kbd into production (staged to coincide with refinery construction) but as those wells come on stream (starting next year) so the effort will swing back to Safaniya, Marjan and the related fields of the NAPR. (And as an aside I had mentioned at the beginning of this series of posts there was some talk of bringing Damman back into production, and those talks are apparently still continuing). This additional production capability will, with the further development of some of the other fields in the region (which I will discuss next time) leaves me believing that, of the three largest oil producers, it will be Saudi Arabia that sustains its current levels of production (give or take 500 kbd) much longer than its two rivals. Though I would again stress the difference between production and export volumes.

OPEC in disagreement, the Saudi dilemma

OPEC Ministers, meeting in Vienna, have apparently had one of their more divisive discussions of recent times over the question of raising pumped volumes.

Saudi Arabia, Kuwait and the United Arab Emirates wanted an increase to dampen an oil price that has gained 25pc since tensions erupted in the Middle East this spring while Libya, Algeria, Angola, Ecuador, Venezuela, Iraq and Iran wanted to keep production unchanged.

The two camps are reported to be so far apart as to threaten the structure of the organization. While the lack of agreement (for the first time in 20 years) officially means that there will be no increase in the quotas of the different countries, Saudi Arabia may, unilaterally, move to increase production in order to meet growing demand and stop the steady increase in price. In the short term, however, the lack of agreement has had the immediate effect of increasing prices.

The proposed increase in volume was 1.5 mbd, which is roughly in agreement with the OPEC projection made through their Monthly Oil Market Reports, of a 1.4 mbd anticipated growth in demand this year. That estimate of demand growth recognized the 0.5 total drop in demand from Japan, though offsetting this with greater growth from China, and anticipating repair of the Japanese refineries. (The next report won’t be out until Friday). Given that we are now in the summer driving season for the largest customers, where demand has normally risen, the move, proposed by Saudi Arabia, would at first sight seem a rational step to keep prices under control.

But given the lack of agreement, the question remains as to whether Saudi Arabia (KSA) and its allies at the OPEC table will increase production in defiance of the rest. Bear in mind that should they have the increase, and prices fall, then those countries that don’t (or can’t) increase production lose money as the price falls. However, if the price rises too much, then the world could be kicked back into recession, and global demand could fall, making everyone lose money on smaller volume.

One has only to look at the latest gas prices in this week’s “This Week in Petroleum” to anticipate how this question over the available supply of crude may well kick the graph back into an upward trend.

US Gas Prices (TWIP )

Demand for gasoline flickered when the price peaked, but then despite the price, and with vacation time beginning, demand has returned to last year’s numbers and may well continue to increase over the next six weeks, following that curve. That depends on how the price changes. Any indication of more oil may hold it at current levels, but without that, as demand grows globally, then without supply to meet it the price will rise until a new balance is reached.

Demand for Gasoline in the USA (TWIP )

But this brings us back to the question as to how great a price increase the world can stand, and concurrently, whether OPEC could sustain a 1.5 mbd increase in production. This really (in terms of a significant step) throws the ball back into Saudi Arabia’s court, since they are the one nation that could provide the increase in volume. And certainly in the short term there are enough wells and fields that could have production increased to give the extra volume.

Life is, however, not that simple. To bring additional complexity to the discussion Goldman Sachs has been suggesting that OPEC production will top out next year, and then begin to dwindle. Since OPEC are sensibly the only folk capable of increasing production significantly to meet growing market demand, that prediction had already roiled the market a little. Non-OPEC production has risen 0.8 mbd in the first quarter, y-o-y, but the gains from the US may be over, at the moment.

US Production of crude (TWIP)

However Saudi Arabia will not over-produce in the short term to hurt the long term production from their fields, thus gains in production in the out years will have to come from new developments. Manifa is the most immediate answer as to where the additional oil will come from, according to the new (2010) Aramco annual review. But with that oil requiring special refineries to process that aren’t anticipated to be available until 2014 for the first, and the second still not finalized, that only gets the increase to 0.4 mbd. There is some additional production that is anticipated from Safaniya, another heavy crude source, but that is directed towards planned refineries at Yanbu and Jazan, but the former is scheduled for 2014, while the latter won’t be ready until 2017. The four new oil fields (Namlan, AsSayd, Arsan and Qamran) that Aramco announced will also take time to develop. As a result the increased production that will come from Saudi Arabia are unlikely to rise much above that available from the recent development of Khurais and Khursaniya, which totals some 1.7 mbd. Some of that new production will concurrently have to offset some of the declining production in older fields

Overall production will be limited to 12 mbd, acknowledged as the maximum sustainable rate for the country, but that number includes domestic use, which is already at 800 kbd and rising.

Unfortunately the 1.5 mbd proposed for the OPEC increase will likely also include any offsetting increased production to compensate for countries in turmoil in the MENA. So, as none of those countries is looking as though stability has yet been conclusively re-established, the combined picture was not really looking that good before we got the news from Vienna.

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.

Saudi Oil Production - read Minister Al-Naimi's small print

Yesterday the Saudi Arabian oil Minister, Ali Al-Naimi, commented that the days of easy oil are not over, and that there remain at least 88 billion barrels in the Saudi oilfield of Ghawar, let alone the rest of the fields in that country. Well before that sends you out to buy a fleet of Hummers, you might want to take a wee bit closer look at some of the other things that he said, or did not say. For the future is not quite as rosy as his remarks might, at first, make you think.

Let’s start with the “days of easy oil are not over.” That is a somewhat egregious remark. It is relatively easy for the Kingdom of Saudi Arabia (KSA) to brag that it is still not that expensive to produce oil. Given the size and extensive development of their fields that is, at present, still to a large extend true for them. But Aramco have carried out extensive research into modeling their fields and developing technologies such as maximum reservoir contact (MRC) on order to get the maximum amount of oil out of their fields. (And I’ll get around to that in a minute). But the KSA only produce a fraction of the increasing amount of oil that the world needs every day. And it is the cost of the oil at the margin (that which balances oil supply with need) that to a much greater degree controls the price.

At the moment the countries that make up OPEC can increase production at need, beyond the current levels of demand. As long as they can do this they can impose controls on the price. This is because the rest of the world is producing just about as fast as it can and there is some doubt, despite some rosy predictions, that they will be able to raise levels above those currently produced. If the price falls too much, then some of the more marginal oil, that is more expensive to produce, might drop off the market. At that point, if OPEC cannot make up the difference, and I would argue that beyond a certain relatively low volume (4 mbd) it no longer can, then prices will rise again. There is an effective lower bound on price now, significantly higher than OPEC costs.

Last week at the ASPO-USA Conference Michael Klare commented on the amount of money that this will bring to the nations that produce oil much cheaper than the global price (which KSA is happy to keep at around $80 bbl) but to keep that price it relies on the make-up oil that is not “easy” at all. This includes oil sand and deepwater production.

Now let me turn to some of the more worrisome part of what he said. Until recently it has been assumed that KSA was going to raise production to levels of 12.5 mbd as part of the balancing act to match declines in other fields and meet supply. (And some time before that there was talk of Saudi production levels of up to 15 mbd). However the KSA has a problem. To get the maximum recovery from their fields they have to control the interface between the waterflood and the oil., and move it relatively slowly and evenly through the reservoir. They are quite good at this, and likely getting better. But it means that they produce the oil at, for them, relatively slow rates. And they are slowing these down a bit. As a result the maximum that they are now talking about is 12 mbd. Which means if you are looking at the global balance over the next few years you have just had to take an eraser and remove 500,000 bd from the available supply. Note that this is not quite 50% more than current production.

Why is this? Well that comes to another part of the remarks that the Oil Minister made. The next major plan for production of oil is the development of the Manifa oilfield. It was, at one time, scheduled to produce a million bd, but this is now dropped to 900,000 bd. But there is a greater concern.

Manifa is a heavy, sour (i.e. high sulfur), vanadium contaminated deposit. It requires a special refinery to process the oil, and these don’t exist. The KSA has had plans in the works for some time to build two refineries in the Kingdom that will refine this oil. There have, however, been delays in construction. It appears that these are getting worse, or, for other reasons, have been further postponed. Without the refineries the ability to produce the oil is meaningless. The original date at which these facilities were supposed to be on line was within the next two. It is now, apparently, been moved to 2024. Presuming that this is not a misprint (since the last target was 2013) it means that KSA has changed its strategy and is not looking to ever produce above the 12 mbd current target as we move into the future.

Naimi said the kingdom has sufficient production capacity at 12 million barrels per day (bpd) and has a strategy of preserving its resources and developing new sources of energy.

"We have the production capacity and we don't have to deplete our reservoirs as fast as someone who's just there for investment...so we don't really have to pull our reservoirs as hard as we should," Naimi said.

With their internal consumption continuing to rise, and with increasing sales to China, the amount of that oil which is going to be available to the West is going to go down.

Whether and when they will get to 12 mbd now becomes more of a question. Given current levels, and the income that they are getting from them, it is hard for me to see production rising to even 11 mbd. (subtracting the volume from Manifa). And if world consumption is rising at around 1.5 mbd per year, for the sake of discussion, then we are going to see an imbalance between production and supply needs, in just about 2 years.

Given that this was the message from the ASPO_USA conference, it is interesting to see the Saudi Oil Minister so rapidly confirm it.

So I’m afraid the difference between the headline of his remarks and the small print of his text are enough apart to be disturbing.

And I must apologize in that this was written on the train from Vienna to Graz and I don't have access to all my usual references, which I would insert.

Seasonality of Demand

Well, with Thanksgiving, and a slight problem in transportation that got us home a day late, it is belatedly time to catch up a little on the latest TWIP report . As we look at reports of weak demand for gasoline and rising stocks, it is important to remember the context within which they are being reported.

Consumption of gasoline is somewhat controlled by season, as is overall oil demand.

Source EIA.

Demand therefore will normally decline in the winter months, and one can see this for the current gasoline demand plot:

Source (EIA )

Demand peaked in August and will now decline until late in February. (Although when, back in that time earlier this year, I looked at these curves I was unable to see a pickup in driving until after April). Looking at how the FHWA record of driving is progressing this month (bearing in mind that the running 12-month total is some months behind current). Overall driving across the country was up 2.5% in September on a year-on-year comparison, and this month there was a gain in all regions of the country. (All but the North-East showing a gain of more than 2%).

Vehicle miles driven reported for Sept 2009 (FHWA )

The changing demand for gasoline with the change in seasons, and the current drop is thus then reflected in the historic change in gasoline prices, which, when averaged from 1990 (taking the data from the EIA) gives:



This is just for regular gas (which is the first column in the table at the EIA that I have derived it from).

Prices have, on average, fallen to a minimum around the beginning of Christmas week, and peaked about the end of June (Morton Downey has a similar sort of chart in Oil 101 which shows that driving peaks at the beginning of August, on average, and is at a minimum in February.

If one looks at the last couple of years, from the EIA plot, one can see that there is, as with demand, a clear seasonality in price, which suggests that no-one should be unduly concerned over prices for the next two or three months, since they will likely fluctuate a little as a result of the normal fall in demand.

Gas prices over the last two years (EIA )

It will be interesting to see, however, what starts to happen as demand picks up, as it normally does, somewhere in towards the end of February and then more strongly in May. Because I suspect that it will be about then that supply might become a little tighter.

We have the Saudi’s at the moment agreeing to hold supplies to the United States at a constant volume, while they previously agreed to increase sales to China as both countries work to cement ties, and while the production from Manifa (h/t Leanan) is pushed back to 2015. Whether this will have any overall impact on the global market will likely become more evident as we move into the summer of next year.

TWIP this week focused on the change in ownership of the refineries in the United States over the past decade. It is best illustrated with this table that they provided.



As you can see, even though there are no new refineries, by improving capacity within existing plant, overall production numbers have increased. The footnote however recognizes the recent closing of the Delaware City refinery and the loss of 210,000 bd of refining capacity.

The Future of Oil - or a gentle Cough at the NYT

The Mining Community is not a really large one, and in our meeting tonight I met folk that have worked on projects that were, for their time, world shattering. But we began the day by remembering, with a moment of silence, the miners that died this past week in Lower Silesia. In a small enough community there were those not present today because of that incident, and we paused to remember that supplying the world with the energy that it needs comes at a certain cost.

And then, after a day of presentations that ranged from presented material that will be in my lectures next week, to promotions that were little more than reading the Web adverts for company products, tonight we had, again, a miners picnic – only this time there was the European tradition of induction for us foreigners into the Brotherhood (except in that – as a ninth generation miner – I think I’m already there, and have done this before) – yet we were led into the assembly in green hoods, leapt the apron and were suitably entered into the community (each country has a slightly different tradition).

A coleague ready to "leap the apron"

I gave a keynote address before lunch today on the problems that the world will face as the economies of the nations resurrect. In a way the talk was “set up” by the CEO of the Polish company KGHM who are running this first Copper Congress here in Lubin. He pointed out that in running a company that uses some 3% of the energy demand for Poland, they have, as a company, to become energy independent since without that security they will become increasingly vulnerable to outside influence.

In the talk that I gave (which was written more for the local audience than as a global message) I tried to walk though the evolving energy changes, and what they would lead into.


Having tied my talk to some 23 slides, obviously I am not going to try and post the entire talk, but perhaps if I go through the theme, you might get the gist of what I was trying to say.

I began with a slide that shows the current top crude oil producers in the world (based in EIA May figures) and noted that, at the moment Russia is at the top. (Note please that since it is late and I still have my “answer” presentation to prepare for the morning, I am not going to give my references tonight). (And if you want to consider that this is a rebuttal to today’s optimistic report in the New York Times feel free to do so).

Then I showed a slide of a well in Samotlor and noted that the Russian historic large fields are running out. Samotlor has declined from 3.2 mbd to 750,000 bd and is pumping, in some wells, 90% water. The Russian strategy has been to find and produce a region until exhausted, and then move East to find the next major depost. That has worked fine as a strategy until now when they have reached Sakhalin Island – on the far East of the country – the next logical place to look is . . . . .

Alaska, and sorry folks, that is already in play, and in fact rather played out.
Which is a good point to introduce the Export Land Model and so I talked just a little about the fact that as a country’s oil peaks and starts to fall, domestic consumption becomes more important and exports suffer a much greater decline than the actual fall in production. Then I showed how this was already happening to Russia, and the impact that this would have on Poland.

To make life even more complicated in terms of those in Eastern Europe with a reliance on Russian oil, I put up a slide showing that the United States is now importing some 840,000 bd of Russian oil, in order to meet its needs, and thus Europe is now competing in the global market for that oil.

Why must America compete in that market – I used a graph showing the collapse of Cantarell (not to mention the other fields in Mexico) and the 100,000 bd fall every three months to show that America has to go to the world market to find the oil that it now needs.

Non-OPEC crude oil production has peaked and is in decline (I used a TOD graph showing the fall since 2004) and so when one looks at countries that have a surplus of production over current supply (comparing IEA and EIA data) the stand-out is Saudi Arabia at either 3.3 or 2.5 mbd (depending on who you believe) with the next largest being the UAE at somewhere between 0.3 and 0.6 mbd.

(And here let me briefly digress to point out that those who wave the NYT story have little clue of the time that it takes between discovery and full field production – nor do they understand oil field depletion, or that just because we have passed peak production does not mean that there is not a whole lot of oil out there that is still waiting to be discovered – only that it is going to be less than the huge volumes that we have already found and exploited).

The problem, as I pointed out, is that the Saudi number includes, among other fields, Manifa, and Yes! we know it is there; Yes! we know that it can produce 1 million bd; but we also have to recognize that until a refinery is built to process that oil (which will not now come on line until after 2013) the use of that production number is a fiction. And thus there is less than 4 mbd available as a current world reserve.

So what else do we need to worry about? Well it was time to introduce oilfield depletion and so I put up the two contrasting graphs that I use from TOD that show decline in current fields when you use 4.5% depletion and then 5.25% (the significant point I indicated was the transition of peak oil from 2011 to 2008).

I then showed a slide with the FT quote that the oilfields in the North Sea were depleting at 9%, and followed it with Dr Fatih Birol’s comment that the depletion rate is 6.7%.

I tied the whole issue together by showing the need that the Western world will have as their economies rebound (about 3 mbd) with the increases in demand from China and India (already 1 mbd and rising) to show that by 2011 we will need some 5 mbd of additional oil over today, but at best have only enough on line to get 4 mbd. (The first Oops Moment).

So now I turned to the second fuel – natural gas – (time was now running a bit tight so this got a little less intense treatment, but also focused on the Polish need).

I began with a slide showing that, over time, natural gas fields were lasting a shorter period of time before they ran out, but then followed this with a slide of Turkmenistan, who has been supplying some 40 bcm to Russia (or thereabouts) for transfer (at a profit) to Ukraine, Poland and Western Europe. To ensure that supply last year (and there were posts on this at the time) Gazprom signed an agreement to pay the prevailing Western price for natural gas to Turkmenistan. Since when there was a collapse in the world price of natural gas and an “accident” to the pipeline between Turkmenistan and Russia means that Russia has not had to accept expensive NG that it has to sell at a loss, since then.

However, just as Russia pressures Turkmenistan to accept a new agreement to sell the gas at a cheaper price, the new pipeline from Turkmenistan to China will open in a couple of months (and I showed the map) meaning that, as China has been willing to pay the higher price (about $8 per kcf as I posted earlier in the week) they have underwritten a cost increase for NG to Western Europe and beyond that is unlikely to go away.

I then quickly put up a map showing the gas shale deposits in the United States and commented that this might at first appear to indicate that we are entering the “Age of Natural gas”, but then I followed this with Swindell’s graph showing that the new wells suffer 60% decline in the first year, and commented that with the high cost of wells, and the current low cost of NG in America (I tried converting prices to zloty per thousand cu m., but may have got a number wrong – we passed a gas station that was selling NG at 2 zloty per liter) the new wells that we need for next year are not being built. Thus we may be competing with Poland for LNG from Qatar.

What is left? I turned to coal (Poland currently gets around 85% of its electrical energy from this source) and I put up my final slide, showing 5 micron coal – which when mixed with 50% water will run a diesel locomotive (and I added a picture of one) as GE have demonstrated.

Which barely gave me time to note that for many countries in the world coal is the only available, viable and economically practical fuel (vide Vietnam and Botswana) at a time when (with a map from “energy shortages”) - which I contrasted with comments from the G-20 Summit - the world is already having serious problems and it was time for me to conclude.

There were no questions (but I was later told that this was due to the format of the session) but I did field comments during the rest of the day.

And so, tomorrow, I have to explain one of the ways they should change to cope with this situation. Excuse me! But I need to put those slides together.