Katla draws a line

Just another interesting geometric pattern:
 
Figure 1 Earthquakes around Katla in the 24-hours to June 30, 2012 (Icelandic Met Office)
  There is no more. . . . .yet!

OGPSS - The Harvard Energy Report, another cough

The OGPSS posts of the last few months have been following a path of looking in a relatively realistic manner at crude oil production with emphasis on that coming from the United States, Russia and Saudi Arabia – the current focus of the weekly pieces. An earlier piece, looked at a Citigroup report of considerable optimism, and the post explained why, in reality, it is impractical to anticipate much increase in US production this decade. Since then, after reviewing the production from Russia, several posts have shown why their current lead in daily crude oil production is likely to be soon over, and that Russian production will then decline, as the oil companies are not bringing new fields on line as fast as the old ones are running out. Saudi Arabia, as the current section of posts are in the process of explaining, is unlikely to increase production much beyond 10 mbd, since Ghawar, the major field on which its current production level is built, is reaching the end of its major contribution, though it will continue to produce at a lower rate into the future. The bottom line, at least to date, is that there is no evidence from the top 3 producers that their production will be even close, in total, to current levels by the end of the decade.
 So, (h/t Leanan) there now comes an Energy Study from Harvard which boldly states that this is rubbish, and that by 2020 global production will be at 110.6 mbd and these concerns that most of us have at The Oil Drum (inter alia) are chimeras of the imagination.
Figure 1. Anticipated Growth in global oil production by the end of the decade (Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012. )
It is therefore pertinent to begin with examining where the study (which was prepared with BP assistance) anticipates that the growth in supply will come from. 
 That too is shown as a plot: 
  
Figure 2. Anticipated sources of the growth in global production by 2020 (showing only the top 23 producers). ((Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012.) 
 It is instructive, in reading this plot, to first recognize that it is a plot of anticipated production capacity, rather than projected actual production. The reason for this can perhaps be illustrated by an example. Within the current production capacity that Saudi Arabia claims adds up to 12 mbd is the 900 kbd that will come from Manifa as it is further developed and comes on line within the next few years. However at that time the increase in production is going, to some degree, to offset the declines in existing wells and producing fields that will become more severe as more of existing horizontal wells water out. Manifa is not currently in significant production, and is unlikely to be at such a level for at least another 18-months, with production being tied to the construction of the two new refineries being built to handle the oil. It is not therefore a currently instantaneously available source of oil. At a relatively normal 5% per year decline in production from existing fields, Saudi Arabia will have to bring on line (and sustain) at least 500 kbd per year of new production, and while it is likely that it can do this for a year or two more, betting that it will be able to do this and to raise production 2 mbd or more in 2020 is on the far side of optimistic. Just because a reserve exists does not mean that it can be brought on line without the physical facilities in place to produce it. 
 It is interesting, however, to note the report’s view on field declines in production:

Throughout recent history, there is empirical evidence of depletion overestimation. From 2000 on, for example, crude oil depletion rates gauged by most forecasters have ranged between 6 and 10 percent: yet even the lower end of this range would involve the almost complete loss of the world’s “old” production in 10 years (2000 crude production capacity = about 70 mbd). By converse, crude oil production capacity in 2010 was more than 80 mbd. To make up for that figure, a new production of 80 mbd or so would have come on-stream over that decade. This is clearly untrue: in 2010, 70 percent of crude oil production came from oilfields that have been producing oil for decades. As shown in Section 4, my analysis indicates that only four of the current big oil suppliers (big oil supplier = more than 1 mbd of production capacity) will face a net reduction of their production capacity by 2020: they are Norway, the United Kingdom, Mexico, and Iran. Apart from these countries, I did not find evidence of a global depletion rate of crude production higher than 2-3 percent when correctly adjusted for reserve growth.

Sigh! I explained last time that with the change in well orientation from vertical to horizontal, that there was a change in the apparent decline rates. This is because when the wells run horizontally at the top of the reservoir that they are no longer reduced in productive length each year, as vertical wells are, as the driving water flood slowly fills the reservoir below the oil as it is displaced. This does not mean that though the apparent decline rate from the well has fallen that it will, in the ultimate, produce more oil.
 The amount of oil in the region tapped by the well is finite, and when it is gone it is gone, whether from a vertical well that shows that gradual decline with time, or from the horizontal well that holds the production level until the water hits the well and it stops. I am not sure that the author of the report understands this. 
 The point concerning support logistics is critical in a number of instances. The political difficulties in increasing production from the oil sands in Alberta, through constraints on pipeline construction either South or West, are at least as likely to restrict future growth of that deposit as any technical challenge. The four countries that the report sees contributing most to future oil supplies are (in the ranked order) Iraq; the United States; Canada and Brazil. For Iraq he sees production possibly coming from the following fields, within the next eight years. 
   
Figure 3. Anticipated production gains in Iraq in the next eight years. (Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012. )
 I understand that one ought to show some optimism at some point over Iraq, but it has yet to reach the levels of production that it achieved before the Iran:Iraq War, and that was over some time ago. The EIA has shown that it is possible to get a total of over 13 mbd of production, but it requires investment and time, and some degree of political stability in the country. That is still somewhat lacking. Prior to that war Iraq was producing at 3.5 mbd, the production curve since then has not been encouraging:

Figure 4. History of Iraqi Production since the start of the Iran:Iraq War. (EIA) 
 Recognizing that the country has problems, the report still expects that there will be a growth in production of some 5.125 mbd by the end of the decade. This appears to be a guess as to being some 50% of the 10.425 mbd that the country could potentially achieve. 
 As for US production, this is tied to increasing production from all the oil shales in the country, which will see spurts in growth similar to that seen in the Bakken and Eagle Ford.

I estimate that additional unrestricted production from shale/tight oil might reach 6.6 mbd by 2020, or an additional adjusted production of 4.1 mbd after considering risk factors (by comparison, U.S. shale/tight oil production was about 800,000 bd in December 2011). To these figures, I added an unrestricted additional production of 1 mbd from sources other than shale oil that I reduced by 40 percent considering risks, thus obtaining a 0.6 mbd in terms of additional adjusted production by 2020. In particular, I am more confident than others on the prospects of a faster-than-expected recovery of offshore drilling in the Gulf of Mexico after the Deepwater Horizon disaster in 2010.

As I noted in my review of the Citicorp report this optimism flies in the face of the views of the DMR in North Dakota – who ought to know, since they have the data. The report further seems a little confused on how horizontal wells work in these reservoirs. As Aramco has noted, one cannot keep drilling longer and longer holes and expect the well production to double with that increase in length. Because of the need to maintain differential pressures between the reservoir and the well, there are optimal lengths for any given formation. And, as I have also noted, the report flies in the face of the data on field production from the deeper wells of the Gulf of Mexico. 
 It seems pertinent to close with the report’s list of assumptions on which the gain in oil production from the Bakken is based:

*A price of oil (WTI) equal to or greater than $ 70 per barrel through 2020 

*A constant 200 drilling rigs per week; 

*An estimated ultimate recovery rate of 10 percent per individual producing well (which in most cases has already been exceeded) and for the overall formation; 

*An OOP calculated on the basis of less than half the mean figure of Price’s 1999 assessment (413 billion barrels of OOP, 100 billion of proven reserves, including Three Forks). Consequently, I expect 300 billion barrels of OOP and 45 billion of proven oil reserves, including Three Forks; 

*A combined average depletion rate for each producing well of 15 percent over the first five years, followed by a 7 percent depletion rate; 

*A level of porosity and permeability of the Bakken/Three Forks formation derived from those experienced so far by oil companies engaged in the area. 

Based on these assumptions, my simulation yields an additional unrestricted oil production from the Bakken and Three Forks plays of around 2.5 mbd by 2020, leading to a total unrestricted production of more than 3 mbd by 2020.

Enough, already! There are too many unrealistic assumptions to make this worth spending more time on. To illustrate but one of the critical points - this is the graph that I have shown in earlier posts of the decline rate of a typical well in the Bakken. You can clearly see that the decline rate is much steeper than 15% in the first five years.Figure 5. Typical Bakken well production (ND DMR )  
Oh, on a related note the Alaskan pipeline was running at an average of 571,462 bd in May.

Katla in Iceland keeps on grumbling

It has been some while since I have posted on the happenings around the Katla volcano in Iceland. I still drop by the Icelandic Met Office site to see how the quake patterns are developing, and the region continues to be the focus of earthquakes that consistently focus around the caldera of the volcano. Something is obviously going to happen, but what and when remain somewhat of a mystery. But I was struck by the pattern of quakes over the past 24-hours. Nothing of any great significance – though I wonder why the quakes are forming the circular pattern? We shall see, no doubt.
Figure 1. Pattern of quakes on Mydralsjokull over the 24-hours up to June 27, 2012 (Icelandic Met Office).
  Jón Frímann has noted that there have been several earthquake swarms in the region in recent weeks, though the most recent did not have any harmonic tremors associated with it. But since this could be an indicator of some thermal activity under the ice cap, it may lead to a flood of melt water from the glacier in the near future. No more.

Native American features and history - an introduction

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

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

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

 

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

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

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

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

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

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

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

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

Rationalizing University courses U-Va and Mining

As the turmoil at the University of Virginia over the firing of their President continues, some of the underlying philosophical divides that drove the action are becoming more apparent. A piece in the Washington Post suggests that alumni of the Darden Business School at U-VA had some major impact on the decision, and that there was some feeling that departments who were not “paying their way” should be discontinued. The article suggests that the cuts would be in liberal arts programs and the classics, and there is a strong defense for continuing such programs.
 I am not going to go into all the reasons why we still need liberal arts programs, they do very nicely at defending themselves and sustaining their presence on campus. However it becomes something a little different when science and technical programs are concerned. My own alma mater, the University of Leeds was provided with a building by the Mining Industry and the last time I went it was occupied by the Art Department, while no-one was quite sure where the last remaining Mining faculty member could be found. (He apparently no longer even has a phone number).
Mining is still a valid occupation, there are vast sectors of the world’s industrial might that would disappear without the material that mining produces from the earth. But that is society’s secret shame, and thus the technology is not defended with the passion that comes from those who seek to retain the classics on campus. (Even though Mining was often one of the founding disciplines of many such a campus).
 With the globe vitally dependant on coal, for example, how many universities in the UK teach mining? How many in the USA? Have these numbers grown or shrunk in the last decade?
  A little personal information – I retired as a senior faculty member in Mining from a mid-Western University a couple of years ago, and had given a year’s notice before I left. So far they have been unable to find someone of adequate qualification to fill the position I left. In fact, due to a similar shortage of faculty who know about taking the ore after it is mined and transform it into the metal used in factories, a discipline known as Mineral Processing, the position will likely now be filled in another group. 
 The discipline that I was fortunate to focus in, that of making holes in things and then stabilizing them led into the use of high pressure water as a tool for excavation. And not just in coal, where I began, but also for tunnels and underground excavations. It is now a multi-billion dollar growth industry with an increasing range of applications. (I was at Logan airport recently and two surgeons were discussing its new use in a medical application, one of the more fascinating areas I found myself in – it can be used, for example, to discriminately remove cancer cells from skin, a technology for which I share a patent).
 Much is made of the fact that continued extraction of fossil fuels at a reasonable cost depends on new technologies as the resources become less concentrated and more expensive to produce. Whether it is the rare earths needed for modern “sustainable” energy producers, the components for advanced batteries or even that mundane black stuff that powers most of the world’s economy it has to be extracted from the ground to be of value. But to create new technologies, you have to some understanding of the current ones. And that requires both knowledge and experience, and within the universities of the country this is becoming a much rarer commodity in the fields that deal with fossil fuels. Do they teach this at U-VA? Well, no – you have to go to Blacksburg and Virginia Tech to find a program in the state (admittedly a good one) but the community is small enough that there is no clout in State or Federal legislatures to sustain a larger program. It is not as though the profession is not in demand, a couple of years ago the average graduate with a bachelor’s degree was starting at a salary of $48,351 petroleum engineers were starting at $86,220 while mining engineers average $64,552. 
Here’s the table:
 
Table 1. Average starting salaries for those with bachelor’s degrees in 2010. (Top 10). 
 The reality is that politics are much more important at the University level is controlling what courses are taught or sustained on campus. At U-Va it is rumored that Dr. Michael Mann – he of the Hockey Stick story on recent temperature rises - (convincingly refuted by A.W. Montford) was to be offered the Kington Chair at U-VA - though with Kington now resigned as vice rector the fate of the chair may now be more in doubt. Makes it sort of unlikely that they will have a fond spot for mining, I suspect. 
 Ah, well nothing much will change, so why get upset – time to find a more interesting topic.

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.

OGPSS - Current oil production and the future of Ghawar

(Updated intro)There is a growing impression being given in the discussion of oil and natural gas supplies, that the world is moving into a period where there will soon be such a plentiful sufficiency of crude that the US may consider exporting some of its production. (h/t Leanan). But if one looks behind the headlines, and particularly at the current status of the largest oilfield contributing toward this rosy picture, the Ghawar field in Saudi Arabia, that optimism becomes more evidently built on a very transient set of data that, as this series of posts seeks to show, will not be sustainable for any significant period into the future.

 The three major oil producers (i.e. those producing more than 5 mbd each) are currently seeing surges in production as the world moves to an overall production of 90 mbd. The OPEC June Monthly Oil Market Report (MOMR) notes that this has brought Russia to 10.33 mbd in May, some 100 kbd over the same period in 2011; and Saudi Arabia is reported to have averaged 9.917 mbd in May, up 40 kbd over April. The United States is running at 6.236 Mbd of crude (from the EIA TWIP), while importing 9.117 mbd. The MOMR reports US oil supply at 9.66 mbd on average, but counts more than just crude in this value. The gain over the past year is around 600 kbd. It is interesting to note, in regard to OPEC production the continued difference between the volumes that OPEC reports from direct contact with the suppliers, and that when the numbers are obtained from “secondary sources.”
Figure 1. OPEC production from its members, with values provided by them (OPEC June MOMR)

 
Figure 2. OPEC production from information provided by secondary sources (OPEC June MOMR).

 This surge from the majors has, in part, led the EIA to project that oil prices will, for the remainder of the year, remain relatively stable.
 
Figure 3. EIA estimate of crude oil prices going forward over the next eighteen months (EIA TWIP)

 In the short term, and leading into a national election, there is no significant event (short of a hurricane or two) that obviously threatens this projection – though the Iranian situation and the questionable stability of nations in the Middle East and North Africa (MENA) has to remain a concern. But sadly the continued ill health of the global economy, with no evident savior or realistic plan for growth now visible, means that demand – which OPEC projects will still grow 1.17 mbd y-o-y on average this year, may continue to be met.

I have, however, in previous posts, given my reasons for anticipating that the surge in both Russian production and that in the United States are at near peak, and will soon decline. Saudi Arabia’s fall will be less dramatic and a little later, but the combination does not bode well for the international supply in the next presidential term. The big question with Saudi Arabian production has been, to date, more focused on the production from Ghawar, which at 5 mbd has been the rock on which the overall production builds. But that rock is continuously eroding under the long production periods that its different regions have seen. The final major new effort to bring new production on line in the overall field was the effort at Haradh, down in the South tip of the field.

 JoulesBurn has written comprehensively on this region, beginning with the first well that came into production. In 1979, as the late Matt Simmons pointed out in “Twilight in the Desert”, the three northern segments of Ghawar, Ain Dar, Shedgum and North Uthmaniyah were producing 4.2 mbd of the 5.3 mbd total Ghawar output, with South Uthmaniyah producing another 400 kbd. By 2006 North Uthmaniyah was running at a 46% water cut. Joules has taken the historic record for that region of the field and made a short movie presentation included in a post that shows how Uthmaniyah was developed over the years.
 
Figure 4. Single frame from the movie on drill site development in Uthmaniyah, over time (JoulesBurn)

 The sequence of wells, moving inexorably to the crest of the field, shows how the wells had to move as the underlying reservoir became more depleted in oil. Uthmaniyah is the region where the test program to inject carbon dioxide to enhance EOR is under construction, as mentioned earlier, and scheduled for completion in the fourth quarter of 2013. It is worth noting that Aramco are also planning on using more steam injection for enhanced oil recovery (EOR) and that plans have just been signed to increase steam production at the Ju’aymah, Shedgum and Uthmaniyah plants, with completion dates in 2014 and 2015.

Figure 5. Sectors of Ghawar with the date of discovery (Afifi )
As one moves south the quality of the reservoir changes, and becomes more difficult to produce. However as Greg Croft has noted the two lower segments of the field Hawiyah and Haradh were developed with horizontal wells, rather than the vertical wells further north in Ghawar. This has overcome some of the geological constraints and the fact that the productivity index drops from around 140 barrels of oil per day/psi to 45 BOPD/psi at Hawiyah, and 31 at Haradh. In 2008 the Hawiyah NGL recovery plant was commissioned, to yield 310 kbd of ethane and NGL. 

 The further development of the lowest segment of Ghawar, down at Haradh, was one of the major projects that Aramco listed as contributing to their ability to produce up to 12.5 mbd. The latest development built on earlier development and because the use of horizontal wells had transitioned into maximum reservoir contact (MRC) designs by the time of Haradh III reduced the anticipated number of wells from 280 verticals to 32 MRC wells.

  

Figure 6. Planned well layout in Haradh III (from Aramco via JoulesBurn) 

 In his initial review of how that developed JoulesBurn showed how the wells were developed and laid out and explained how he was able to use satellite images to determine the different components of the production equipment. It is relevant to note that Joules updated his view of the region in 2010 when he noted that, after looking at the satellite images of the region, he was able to show that instead of the production coming from the original 32 wells, there were actually some 52 production wells connected up, which – as he noted – raise a few questions as to the actual performance of the wells over the original projections. 

 Aramco have reported, however (pdf) using Real-Time Reserve Management, that it had by the summer of 2009, been more successful than anticipated. Some of the additional wells drilled were to allow cross-hole tomography (pdf) to monitor the location of the oil:water front which, as production evolved, did not follow the anticipated path. This was particularly important to establish given the 1 km spacing between wells and the more complex geology relative to that further north in Ghawar. 

 

Figure 7. Schematic showing how cross-hole tomography is carried out (Stephen Prenskey ) 

 

Figure 8. Image from Crosshole tomography at Haradh (out (Stephen Prenskey) 

 What is, however, also clear from looking at the different regions of Ghawar is that there are no places left for new programs to restore production as wells become exhausted. If KSA is to sustain its production it must look beyond the King of Oil Fields, who now lies stricken in years.

OGPSS - Saudi Arabia and Natural Gas Liquids

Stuart Staniford has been watching the decline in oil prices. He has then commented that, given the Saudi need for income to hold off “Arab Spring” dissatisfaction, they are unlikely to let prices fall too far, before cutting production, since even a 10% reduction in output could raise prices 20%, thereby resolving possible income concerns. This well reflects the role of the Texas Railroad Commission back when, which controlled US production in order to sustain an acceptable price for oil. But that role collapsed when overall US production was no longer able to spring to the rescue when demand rose, and US production could not, passing the control over prices to OPEC and more particularly the Kingdom of Saudi Arabia (KSA) who could, and have shown a willingness to, control output to ensure that it proximately followed demand and has kept prices within an acceptable range, for them.

 It is easier to do this by curtailing production, and as Stuart noted, this can increase KSA revenue at a time of falling global demand. However, in the opposing case, where the global economy requires a “reasonable” price for oil, and will require them to increase production, as they have done to the limits of demand growth in the past year, that ability may be limited and of a shorter duration. It also occurs at a time that the internal use of crude is limiting the amount that the KSA can export. But while there is considerable discussion about this situation, there has been some increase in natural gas liquid production that is also important, and thus a main point of this post.

 

Figure 1. Recent KSA production and exports of oil (Export Databrowser )


In the past, when the Kingdom has been challenged on the ability to increase production, it has listed the number of future fields that it would bring on line. Previous lists of future projects are, however, now reaching completion. Shaybah, for example, in the Empty Quarter, raised production in January 2009, from 500 kbd to 750 kbd, and will soon raise it an additional 250 kbd to 1 million barrels a day.


 The increased production at Shaybah, however, also helps identify an additional source of increased production, since is also increasing natural gas production to 2.4 bcf/day, with a concomitant production of 264 kbd of NGL. The increase in overall production of NGL from OPEC has, for some time, provided a significant volume of additional fuel. By the last quarter of 2011 OPEC as a whole was producing 5.42 mbd of NGL and NCF (non-conventional fuel), (up from 3.89 mbd in 2006) Rune has written about NGL production here and here with the relative importance of this supply perhaps best illustrated with this graph from the latter post. 

 
Figure 2. OPEC crude oil, condensate and NGL supplies over the decade from 2001 to 2010 (Rune Likvern) 



 OPEC is anticipating an overall increase in NGL production from the 2011 average of 5.3 mbd to 5.7 mbd in 2012, with final quarter 2012 volume reaching 5.86 mbd. Apart from the increased supply from Shaybah, KSA is developing the Arabiyah/Hasbah offshore fields with onshore processing at Wasit. This will produce 2.5 bcf/d of natural gas, with 240 kbd of NGL production associated with that. 


There is also the development of the Karan field that will, with the other programs in development, collectively raise KSA natural gas production to 15.5 bcf/day from the 10.2 bcf/d it was achieving in 2010. Unfortunately the high sulfur content of the gas to be fed to Wasit is causing some problems and that project completion may now be delayed until 2015, though the problem (of sulfur freezing in the lines) is not yet solved. Saudi production of NGL’s has steadily grown over the years.


 


Figure 3. Saudi Arabian NGL production (Index Mundi from EIA ) 


 Last August, for example, it shipped 197,824 metric tons roughly equivalent to 66 kbd, of exports through ports under the Saudi Port Authority – note that this does not include the amount used internally, but was 79% up on the previous year and does not include shipments from ports operated by Saudi Arabian Oil Co, or by Aramco. It should be also be noted that, following the drop in consumption caused by the recession, the United States has increased the amount of crude that it is importing from KSA over the last couple of years.

 


Figure 4. U. S. Imports of Crude and Petroleum Products from Saudi Arabia (EIA) 


 However, because of the increase in the volume of natural gas produced in the United States, there has been a concomitant rise in the amount of NGL produced. The volume of NGL produced varies with the field, with the relative differences shown in the following figure.

 


Figure 5. Volume of NGL produced per kcf of natural gas in different fields around the United States (NPC North American Resource Development Study) (PDF)


 In 2010 the US averaged a production of 2.42 mbd of NGL, and were production of natural gas to rise to 110 Bcf/day by 2035 as has been projected by some, this will, at that time yield some 3.9 mbd of NGL with an additional 0.69 mbd from refinery production. The US does not, sensibly, import any NGL, and with rising production will likely start exporting to Canada, where production is declining. The Saudi market for NGL lies largely in Asia, with an export terminal at Yanbu The terminal is connected to Abqaiq through a 1,170 km pipeline, and can handle exports of up to 2 mbd of NGL.

Rising Energy Prices and their impact

As the United States continues through the interminable process that will end with the national elections in November, the continued poor state of the economy is playing an increasing part in the debate over the likely outcome. What seems to have slipped from the discussion, however, is the contribution that energy costs are making in their impact on the different economies around the world including that of the United States. That awareness is becoming more evident in the UK, particularly in the debate over Scottish Independence. The recent Uswitch report notes:

Energy bills have more than doubled in the last 8 years – if this trend continues bills could reach £1,582 a year by 2015 and £2,766 by 2018. But almost six in ten people (59%) say that energy will become unaffordable in the UK if the average bill hits £1,500 a year, with the average household bill today already £1,252 a year.

Yet the increasing reliance on “green energies” in the United Kingdom, and particularly Scotland, are already recognized as leading to major current and future cost increases, with consequent impacts on the strength of the economies that they support.

Figure 1. Relative energy sources for Scotland and the UK in 2010 (Scottish Government)

 The growth of renewable energy in Scotland has been remarkable over the past decade, and has received consistent support to grow beyond the current levels. The major growth has been in the use of wind turbines, which – as I saw in a recent trip to the UK, are now more prevalent than ever. (And, more encouragingly, were also turning in greater proportion than I had seen in the past).

Figure 2. Installed capacity for renewable energy in Scotland through 2010 (Scottish Government)

  Current plans and projections would increase capacity from the roughly 4.4 GW shown above to a total of 28.8 GW being possible with pipeline and projected other projects. And in 2010 Scottish turbines produced more power from turbines than from hydro power for the first time.

Figure 3. Scottish electricity from renewables by source (Scottish Government) 

 Of these, however, only 3.3 GW have progressed beyond the planning stage. Yet, given that renewable sources have supplied nearly 20% of the need at present, this suggests a much greater role in the future, with less need for more conventional fossil fuels. Currently Scotland gets most (around 75%) of its electricity from five power stations, there are the two coal-fired power stations at Longannet and Cockenzie, one gas-fired station at Peterhead, and two nuclear power stations at Torness and Hunterston. These stations will be phased out as the transition to greater reliance on “wind and wave” with a target of 16 GW to be contributed in 2020.

Figure 4. Path to a Scottish Renewable Energy Future (Scottish Government ) 

 (A. Deployment projection based upon an extrapolation of the annual deployment levels experienced in 2007-08. 

B. Deployment projection based upon an extrapolation of the annual deployment levels experienced between 2009 and the start of 2011. 

C. Deployment projection, based on Scenario B above, adjusted for the improvements in the planning/consent system that were introduced in recent years but which have not yet impacted upon actual deployment rates. 

D. The 100% target line is a straight line extrapolation between current installed capacity and the estimated levels of capacity required to achieve 100% of gross consumption from renewables in 2020. 

This hypothetical line is incorporated to identify and acknowledge the scale of the challenge. In reality, it is recognised that deployment will not follow a straight line and would be expected to accelerate towards the latter part of the decade, particularly given the potential magnitude of offshore wind deployment.) 

 The political beliefs of the Scottish National Party (SNP) now in power, which include a desire to reject nuclear power and move to greener sources of electricity is, however, bumping up against the realities of cost and practicality. The Institution of Mechanical Engineers in the UK has released a report that concluded:

The Institution’s findings suggest that the original renewable energy target split for Scotland of 50% electricity, 11% heat and 11% energy for transport, making the overall 20%, and subsequent revision of the electricity generation target to 100%, did not appear to be supported by a rigorous engineering analysis of what is physically required to achieve a successful outcome in the timescale available. 

During the research for this report, First Minister Alex Salmond announced that the Scottish Government had increased the overall percentage target for energy from renewable sources to 30% by 2020. In light of this report’s analysis, this aspirational target appears to represent an ambition that cannot be justified from an engineering perspective.

The Scottish Government has responded, in part, by emphasizing the goal of reducing energy consumption in the country by 12% by the year 2020. Yet significantly raising energy costs and demanding that society reduce demand are not obvious ways of immediately stimulating economies to return to national prosperity. About 750 million British pounds (BP) ($480 million) worth of power came on line in 2011, but the investment required to meet targets in the future will be much higher. The estimated cost for the next 17 GW of capacity is $70 billion (46 billion BP). The Scottish GNP runs around $225 billion (145 billion BP) and there is increasing question over the ability of the country to be able to attract the funding needed to achieve its targets. 

 Yet the concern that worries me more as these debates continue is that while an increasing reliance on renewable energy sources may well be politically promoted, the financial and technical ability to reach those goals is becoming increasingly unavailable. (See particularly the IME report). For, while the focus of the debate remains on that side of the supply, the construction of alternate power sources to meet the anticipated demand are not being properly addressed.

 In Scotland there is now talk of a new coal-fired power station at Grangemouth following the cancellation of a carbon capture and sequestration project at Longannet. The Cockenzie coal-fired plant will close next year, though there are hopes that it might be replaced with a natural gas-fired plant. But these things take time to permit and construct, and should the required pace of renewable sources falter, then the conservation of energy that the Scottish Government would like to see as a voluntary activity might come to be an involuntary need instead, with consequent significantly more severe impact on industry and the Scottish economy. 

 Why is this relevant to the American election? Well unfortunately, though at a slower pace, there seems to be a similar argument being made in the United States to speed up the phase-out of coal-fired power, as perhaps evidenced by the recent decision to close the Big Sandy coal-fired power plant in Kentucky, under EPA pressure. There is a presumption in discussions of the future energy costs for the country that cheap natural gas will be an easy replacement for coal. However, much of that future relies on the low prices of natural gas, and as Chesapeake are finding, just because there is a market, does not mean it is a profitable one. You can’t make up the difference between producing natural gas for $5 a thousand cu ft (kcf), and selling it at $2/kcf by increasing the volume that you sell, and thereby realize a profit. When all the dust settles it is likely there will be less natural gas on the market, at a greater price, but that is a different story. For now one can only be concerned that the failure to recognize that energy prices are playing their part in restraining national economies seems to have become a neglected part of the national discussion, which is a pity – both in Scotland and in the USA.