OGPSS - The production from the Kingdom of Saudi Arabia - part 1

The United States Government has just asked the Kingdom of Saudi Arabia (KSA) to raise the levels of its oil production this summer. Oil production is otherwise anticipated to be at some 9.8 mbd this summer, with fluctuations of around 200 kbd about that number. (There are rumors it has just hit 10 mbd.) It is reported that the KSA could raise production to 12.5 mbd if needed. And the Saudi Oil Minister, Ali al-Naimi has now stated that the KSA is able to meet that commitment.

Since I started writing about peak oil back in 2005, the possible maximum sustainable production achievable from the Kingdom has been one of the recurring issues at The Oil Drum, and there have been a number of very perceptive analyses carried out by folk such as Euan Mearns, Stuart Staniford, and JoulesBurn that I do not intend to try and surpass. I will, however, try and summarize some of their conclusions as I work through a few posts that look at the overall production from the various fields that are found both on and offshore Saudi Arabia.

As an initial point, not all the oil that comes from the country is of the same quality, and this is often one of the initial factors that folk do not appreciate when they look, for example, at the two numbers I gave above, that which the KSA is producing, relative to that which it might be able to achieve. The problem arises with the heavier crudes that make up a part of the surplus, and for which there is not a great market out there, as yet. So let me begin the review with, this week, just simply looking at an overall view of the country, the oilfields that comprise regions of major production and what sort of oil that they are producing.

Back in 2005, production from the different oil fields added up to 9.07 mbd, and at the time I had figures suggesting that the total broke down as follows:

Abqaiq 400 kbd;
Abu Sa'fah 200 kbd;
Berri 300 kbd;
Ghawar 4,500 kbd;
Hawtah 200 kbd;
Hout 300 kbd;
Khurais 300 kbd;
Marjan 270 kbd;
Qatif 800 kbd;
Safaniya 700 kbd;
Shaybah 600 kbd; and
Zuluf 500 kbd.
This adds up methinks to 9.07 mbd.

JoulesBurn has since pointed to me that my initial attributions were incorrect and that, in a paper given in 2006, Mendez et al had reported that the target for Hout was only 50 kbd, while that for Khafji was 300 kbd. I will explore those issues more in later posts on this region. But a hat tip to JB for catching my error.

The major fields in Saudi Arabia (EIA)

Not all these fields have oil of equivalent quality, and this is a point that often fails to be understood when there is a global shortage and the KSA offers more crude to the market. If that crude is sufficiently sour (i.e. too much sulfur) and heavy (low API gravity) then it cannot be refined by some of the refineries that may be hurting the most. Thus the oil might not find a market, even though there is a shortage. What the KSA tries to do is to swap deliveries, but that does not always work as it might.

Different grades of oil supplied by Saudi Arabia.

(For those who have forgotten the API gravity classification in degrees, I explained it in an earlier post. Suffice it to say that the higher the number, as a general rule, the lighter the crude and the better the market. As the share produced from the historic fields changes, so the KSA has offered the heavier crudes to the market, but, as I noted, even with the increase in global demand, those crudes have been less successful in finding a permanent market.)

Way back when the world was more innocent, there were four major fields that produced most of the oil from KSA:
Ghawar (the King), which started producing in 1951. Peak production was at 6.6 mbd. Current production is under 5 mbd. Water inflow percentages are increasing, and overall output is decreasing. It is divided into various regions, Ain Dar oil has an API gravity of 34, and 1.66% sulfur. Shedgum is at an API gravity of 34 and sulfur content of 1.75%. Uthmaniyah has an API of 33, and 1.91% sulfur. Hawiyah is at an API gravity of 32,and 2.13% sulfur, while Haradh oil has an API gravity of 32 and 2.15% sulfur. The levels of sulfur define how “sour” the crude is, and this must be recognized by the refineries, such as the Fujian Refinery in Quanzhou, China which is designed to refine 240 kbd of sour light Arabian crude. The oil from Ghawar flows to the Abqaiq processing plant, this can handle up to 7 mbd of light and extra-light crude., and cleans the crude before sending it on to refineries at Ras Tanura, Jubail, Yanbu and Bapco.

Abqaiq (The Queen) saw peak production in 1973 at 1 mbd, has now fallen to a level of around 200 kbd. It is a field that is “rested” from time to time in order to sustain an even displacement as the water flood progresses. The oil is at API 36.

Safaniya (2nd Queen) started producing at 50 kbd from 8 wells in 1957, peak production was at 1 mbd, and is now down to about 770,000bd. The field lies offshore, and is a producer of some of the heavier crudes, with an API gravity of 26, and a sulfur content of up to 2.96%. It has a current production capacity of 1.2 mbd, but because of the heavier nature of the oil has more trouble in finding a world market, and thus often much of this production is withheld. (In 2008, for example some 700 kbd was being withheld from the market.) The field is currently being further developed with a larger pipeline being installed to allow a higher flow rate from the field onshore. It is also intended that the gas that is now flared will be captured. The upgrade will also involve the installation of submersible pumps and an upgrade to the distribution network, and is scheduled for completion in late 2013, when the capacity will rise to 1.5 mbd.

Berri (the Great Lord) saw peak production at 788,000 bd in 1977 and more recently that fell to around 300,000 bd. This was the fourth of the original set of fields in Saudi Arabia that were responsible for 93% of Saudi production back in 1978. It is slowly watering out and has been occasionally left resting except when additional production is required. The oil has an API gravity of 38, with about 1% sulfur. The field has been reworked so that it now has a capacity of 1.15 mbd though some 300 kbd of this is considered part of the reserve production in case of need, rather than normal production.

Looking back seven years, the plans that the kingdom had, back then, for sustained and increasing production (they recognized that existing wells would decline and thus planned for their replacement) were clearly stated by Abd Allah Al-Saif :

major projects that Saudi Aramco is undertaking to ensure meeting future demand:

The Abu Sa'fah and Qatif projects came on stream in 2004 adding 650,000 bpd.
300,000 bpd of Arabian Light will come on stream in the Haradh field in mid-2006.
500,000 bpd of Arabian Light will be added to capacity through the Khursaniyah development, planned for 2007.
2008 is the target date of approved expansion plans that would add 300,000 bpd of lighter crude at Shaybah and central Arabian fields.
A Khurais increment of 1.2 million bpd of Arabian Light will be commissioned in 2009.
"This is a very aggressive program that will require the mobilization of immense resources, such as rigs, material and manpower, but which we are confident to successfully execute, as we have done for the past 70 years," he said.

Concerns at the time, over the ability of the kingdom to meet these plans focused not only on the quality of the mix, but were more immediately initially aimed on the number of drilling rigs that the KSA had available to drill the required number of wells. Back in 2005 the country did not have a whole lot of rigs at their disposal. This has since been highlighted by Euan Mearns:

Rig Count for the Middle East (Euan Mearns 2011)

Bear in mind that when we started posting we were just coming to the end of the relatively flat section of the Saudi plot, and were, at the time, unable to see how they could continue operations with only 20 odd rigs. Well, with hindsight they could not, and as the plot suggests they rapidly acquired all the spare rigs available at the time and this allowed the increase in the number of wells that afforded the new levels of overall production. Sam Foucher has also posted on the rig count, and his plot agrees more with my memory of the dramatic transition in rigs that the KSA employed back in the 2006-7 timeframe to move them from the placid conditions pre-2005 to the sudden realization that BAU would no longer work.

Various Saudi plots from Sam, though the critical one is the rig count change (Sam Foucher)

The point of the illustration is to indicate that circumstances do change operating conditions, and that folk do respond when they have to. Up, that is, to the limits that they are able to achieve. Some of those limits are imposed by the fact that you cannot suck beer from a conventional pint glass forever, as I discovered when in college, and it is in regard to those issues as well as some more of the above that the discussion will swing toward as the next few weeks unfold.

There have been many other posts on the subject on the Oil Drum over the years, (if one includes Drumbeat there are more than 2,000) here are but a very few
JoulesBurn- Abqaiq
Intro to Satellite sleuthing
Khurais me a river
Happenings in Harmaliyah
Ghawar Numerology

Stuart Staniford
Satellite o’er the desert

Euan Mearns
Saudi Production laid bare

I will add to this list as I move on and start to address some of the concerns that have been raised.


Normandy Inn
Carmel-by-the-Sea

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.