Guest correction by David Middleton
One of the comments (H/T to RicDre) on my post about Arctic oil exploration cited this article from Bloomberg/MSN Money…
The biggest Saudi oil field is fading faster than anyone guessed
Javier Blas 11 hrs ago
It was a state secret and the source of a kingdom’s riches. It was so important that U.S. military planners once debated how to seize it by force. For oil traders, it was a source of endless speculation.
Now the market finally knows: Ghawar in Saudi Arabia, the world’s largest conventional oil field, can produce a lot less than almost anyone believed.
When Saudi Aramco on Monday published its first ever profit figures since its nationalization nearly 40 years ago, it also lifted the veil of secrecy around its mega oil fields. The company’s bond prospectus revealed that Ghawar is able to pump a maximum of 3.8 million barrels a day — well below the more than 5 million that had become conventional wisdom in the market.
“As Saudi’s largest field, a surprisingly low production capacity figure from Ghawar is the stand-out of the report,” said Virendra Chauhan, head of upstream at consultant Energy Aspects Ltd. in Singapore.
[…]More mistakes at MSN Money
My first thought was that 3.8 million bbl/d (barrels per day) was a reasonable number. It had long been assumed that Ghawar was producing around 5 million bbl/d. An Aramco presentation on water cut management showed the production a little over 5 million bbl/d in 2004. Prior to Aramco’s decision to move toward an IPO (initial public offering), they were very secretive regarding production and reserve details. In order to be listed on major stock exchanges, Aramco has had to open their books up to independent auditors. The recent independent audit by DeGolyer & McNaughton actually boosted Aramco’s proved reserves. There are nearly 100 oil fields in Saudi Arabia, including several giants besides Ghawar. It just happens to be the biggest.
With about half of Ghawar’s EUR (estimated ultimate recovery) having already been produced, the field should be in decline. It will produce for another 40 years or so, but the rate should slowly decline over time. The Bloomberg/MSN Money article claims that Aramco’s 2019 bond prospectus shows the maximum production rate to be 3.8 million bbl/d. If so, it’s now producing at a slightly lower rate than the entire Permian Basin and would reflect a 2% decline rate, less than half of the typical 5.7% decline rate for mature oil fields. This shouldn’t surprise anyone. Even if the article was accurate, it would fall into the No Schist Sherlock category.
However, it turns out that the Bloomberg/MSN Money article was not even wrong.
[T]here is fairly little in this prospectus to give us a sense of Aramco’s coming production numbers in a week, a month, a year, or ten years. Nevertheless, an article was published on Tuesday claiming that Aramco’s supergiant oilfield Ghawar is “fading faster than anyone guessed,” and it helped move oil prices higher.
The article incorrectly asserts that capacity at Ghawar field has dropped, though we do not know this to be true. Ghawar has long been the largest and most productive oilfield in the world, and the article accurately states that it produced 5 mbpd as recently as 15 years ago. It is the most famous oilfield and it is seen as a staple of oil production in the industry, so any news that it is getting old and declining sparks fear of “peak oil” among traders.
In truth, the Aramco bond prospectus provides little information about Ghawar’s current or future production. The only information it does provide is in the form of something called the “MSC.” This term is refers to the capacity that Aramco is required by law to be able to access within a three-month timeframe.
The Saudi Hydrocarbons Law sets the total Saudi MSC at 12 million bpd. In other words, Aramco must be able to ramp up production from whatever level it is producing to 12 million bpd in just three months time, and Aramco must be able to hold the 12 mbpd level for one year. In accordance with this requirement, Aramco breaks down that production by field. So, if for some reason it becomes necessary for Aramco to increase production to 12 million bpd, Ghawar field’s responsibility is to produce 3.8 million bpd.Investing.com
Being curious and knowing a little bit about the oil & gas industry, I downloaded Aramco’s nearly 500-page prospectus and did a little research (about 5 minutes’ worth)…
The Company maintains MSC in accordance with the requirements of the Hydrocarbons Law. MSC refers to the average maximum number of barrels per day of crude oil that can be produced for one year during any future planning period, after taking into account all planned capital expenditures and maintenance, repair and operating costs, and after being given three months to make operational adjustments. As at 31 December 2018, the Company’s MSC was 12.0 million barrels of crude oil per day. The spare capacity afforded by maintaining MSC enables the Company to increase its crude oil production above planned level rapidly in response to changes in global crude oil supply and demand. The Company also uses this spare capacity as an alternative supply option in case of unplanned production outages at any field and to maintain its production levels during routine field maintenance. The Company generated revenues by utilising the spare capacity provided by MSC of SAR 133.0 billion ($35.5 billion) from 2013 to 2018.Saudi Aramco
From the Aramco prospectus (p. 88):
“Liquids” refers to proved reserves of crude oil, natural gas condensate and natural gas liquids. “Combined” refers to proved reserves of liquids plus natural gas. “MSC” refers to the maximum sustained production rate “during any future planning period.” It does not refer to the current maximum production rate. Ghawar could be producing much less or much more than 3.8 mmbpd. The MSC rate is more of a minimum rather than a maximum. Aramco is basically guaranteeing that Ghawar’s maximum sustained production rate will be at least 3.8 mmbpd for the foreseeable future (“any future planning period”).
The really funny thing is that Wikipedia has already incorporated the Bloomberg/MSN Money mistake…
“The Biggest Saudi Oil Field Is Fading Faster Than Anyone Guessed”. April 2019.List of oil fields, Wikipedia
Note to Wikipedia, Bloomberg and MSN Money…
I used to work in the oil business. Nobody knows who much oil is in the ground yet to be removed.
Estimating how much oil and gas was in a certain field was nothing more that guess work and fun with numbers.
At this drilling company I worked for back in the 80’s, to estimate how many barrels of oil and cubic feet of natural gas a field may contain, the usual formula is to take the hoped for return on investment over a certain period of time and divide by the current price for oil or natural gas and that was what was used to determine how much petroleum a well would yield.
If a field turned into a producer, that was the number presented.
All it is is putting some numbers to a wild a$$ed guess. So is it a surprise that field yields more (or less) than what is estimated. Nope, not at all.
It’s not guesswork. And that’s not even close to how reserves are estimated or production rates are forecast.
David, thanks as always for your excellent energy articles.
Thank you D. Middleton.
I value thoughts well formed.
David LeBlanc, your comments are wrong and offensive. Maybe the comment “I used to work in the oil business.” is a clue as they got rid of you. I was on a technical committee for a large oil company and I assure everyone that oil companies avoid self-delusion (while trying to maximize shareholder wealth, of course).
Reservoir volume x porosity estimate = estimated volume of which 60% can probably be extracted.
Reservoir volume by seismic survey.
One well and a seismic map per discovery covers about 90% of what I’ve booked over the past 30 years.
It’s more complicated than that, but you’re on the right track.
Original oil in place is directly calculated from reservoir thickness, area, porosity, water saturation and a few other variables.
The recoverable oil is related to the drive mechanism. A really good water drive oil reservoir can yield a 50% primary recovery of the original oil in place. However, 20-30% primary recovery is more likely, because pressure-depletion is usually a factor.
“All it is is putting some numbers to a wild a$$ed guess.”
We have exhausted the “proven reserves” of oil many times over, and yet, the “proven reserves” keep expanding.
(Isn’t capitalism great?)
Note that the figure for natural gas is the bbl equivalent of trillion cubic feet.
I was an Aramco employee for 21 yrs. Yes the Ghawar mega field is/has been depleted due to water flood, but still available for enhanced recovery techniques. This is true for all gas/oil fields. Conventional drilling techniques were used in the past to gather the low hanging fruit, but current drilling & recovery techniques stretch out the recoverable oil from currently producing fields. Unless you have worked in Saudi Arabia for 20 yrs or more you can’t really get a grip on what the extent of the reserves are. It is really unbelieveable. The Saudis do not suck oil from wells, it come out natually pressurized. It used to be that one Saudi well was equivalent to about 2000 pumped wells in the US.
The water flood gets them close to a 50% recovery. CO2 injection will push it up to about 80%. The Arab-D carbonate is one of the most phenomenal oil reservoirs imaginable.
The high pressure is from deep CH4.
This is true for most of the middle east.
Not even wrong.
There are immense amounts of CH4 in the middle east.
There are now with recent discoveries immense amounts of CH4 in other locations.
Qatar’s proven natural gas reserves stood at approximately 890 trillion cubic feet (Tcf) as of January 1, 2009. Qatar holds almost 15 percent of total world natural gas reserves and is the third-largest in the world behind Russia and Iran. The majority of Qatar’s natural gas is located in the massive offshore North Field, the world’s largest non-associated natural gas field. The North Field is a geologic extension of Iran’s South Pars field, which holds an additional 450 Tcf of recoverable natural gas reserves.
There is some much CH4 in the middle east that it was once just flared.
They flare it because they can’t sell it.
At $3.00/mcf, natural gas is equivalent to $18/bbl of oil… They make more money on the oil by flaring the gas.
In other words, the Greenpeace and the Green party of KSA (what) do not much have a foothold there.
So they concentrate on killing drilling in the USA / Canada.
The reason why it is just flared is because it probably has SO2 gas in it, so add some water and it makes sulfuric acid. Pump that. Your equipment won’t last long.
Or burn part of the H2S to removed from sour natural gas, produce SO2 and combine the two to reduce it all to liquid sulphur for sale, mainly to the fertilizer industry as they have been doing in Canada for half a century or so:
2H2S + SO2=> elemental S +2H2O
Canada was the world’s largest sulphur exporter for decades.
Canada does not flare sour gas. H2S is removed as elemental sulphur via the Claus process. The sulphur is then sold out of the Port of Vancouver or burned locally to make sulphuric acid which is then used for fertilizer (conversion of phosphate rock) and other industrial applications.
That would be H2S, not SO2 and most Saudi crude is “sweet”… it has a low sulfur content.
Or not. Saudi crude is “light” but not “sweet.” If averages nearly 2% sulfur content.
You cannot make sulphuric acid by adding water to SO2. You are thinking sulfurous acid. To make sulphuric acid you need to pass SO2 over a vanadium pentoxide catalyst to get SO3 then add your water.
O/T, but on the same page they also link to a story about how deeply Royal Dutch Shell has been quaffing the global warming kool aid, to te extent that they are withdrawing from an industry association that doesn’t sing from the Paris hymn-sheet:
And their published report on the topic:
Slightly worrying stuff, unless one takes the view that they are really just positioning themselves to look angelic when compared to the rest of the industry, and thus more attractive to investors.
They are talking their book. Shell is weighting more to Nat Gas (eg purchase of BG).
They’ve also divested from some oil sands assets.
Here’s a presentation from Shell North America president Hofmeister from some years ago now. Interesting to see how their view/strategy has evolved
View From the Top: Shell Oil President John Hofmeister
June 27th, 2007
John Hofmeister, Shell Oil president, sees an important role for his company in supplying the world’s energy in the future. Petroleum (oil and gas) will remain, at least for the near to medium future, the most important energy resource. Shell is also investing, as are many other energy companies, in renewable energy (wind, solar, biofuels) as well as so-called clean coal. Hear John Hofmeister’s views on Shell’s future directions and current energy policies.
In business and in personal life- much of what passes for virtue is really self interest with a strong flavouring of hypocrisy.
Shell’s plans to cut carbon emissions beginning in 2020
Published on Dec 4, 2018
Political appeasement- license to operate
Hofmeister advocates Nat Gas as source for transportation Fuel
Published on Dec 4, 2018
Former Shell Oil president talks rising oil prices
That fields has bad sea water intrusion problems and the volume pumped is probably 75% salt water. Average oil field lasts 20 years, large ones 40. That one at 40 is a ghost.
We’ll be awash in hydrocarbons once we can harvest the CH4 from the ocean floor.
If we don’t find a way, the Chinese will.
Based on this economic analysis, methane hydrate production would be uneconomic…
At the time this was published, 42-174 JPY/m3 worked out to about $12-$45/mcf… Equivalent to oil prices of $71 to $269/boe.
That’s still less expensive than wind farms and solar cells, that is, unless you are living in the outback.
An acceptable extraction methodology would require that a rich ocean environment would remain virtually untouched, though.
It’s safe to say that CH4 extraction is currently unfeasible.
There’s no doubt there’s a lot of natural gas there… over 1,000 years worth of current consumption. It’s just not possible with current technology to deliver economic production rates from methane hydrates.
We do not need to harvest methane hydrate on the ocean floor.
There are immense CH4 reserves all over the planet.
For example, the Canadians were planning a LNG import facility 20 years ago, based on the ‘fossil’ paradigm.
The Canadians are now planning to build a $40 billion dollar, LNG export facility.
The decision to build a $40 billion dollar CH4 export facility on the coast of Canada is based on CH4 ‘reality’ which is the fact that there is a middle east sized CH4 reserve, in Canada, which will feed that massive new terminal.
$40B LNG project in northern B.C. gets go-ahead
Chevron asks NEB for licence to nearly double Kitimat LNG project
Scientific Paradoxes to Explain: Heavy Oil and Bituminous Coal, Heavy Metal Paradox:
The fossil paradigm cannot explain why helium is found in all CH4 reservoirs. All helium is produced by the radioactive decay of uranium and thorium.
To produce helium to get into the reservoirs there must be uranium and thorium below the CH4 reservoirs. As there are CH4 with with more than 0.3% helium in them there must be concentrated uranium below them. The fossil theory cannot explain why there is concentrated uranium below the natural gas reservoir.
High viscosity crude (sticky crude) and bituminous coal also contain heavy metals, including uranium. The refinery bottoms from refineries that process the most heavy/viscous crude is purchased and process to remove the uranium. The amount of heavy metals in the crude increases for sticky (higher viscosity) crudes.
Good fracking grief…
Helium is rarely significantly present in natural gas reservoirs. It only occurs in reservoirs that are over granitic rocks and overlain by an exceptionally impermeable trapping formation.
David there are multiple new observations which are easily be explained to lay persons which is interesting as the observations can only be explained by massive amounts of CH4 continually coming into the biosphere.
Thomas Gold and the Soviets where on the correct theoretical path. Scientists and geologists from the old Soviet Union believed as they still did that hydrocarbon deposits on the surface of the earth where created by CH4 moving up from the deep earth, not from the conversion of biological material into CH4 ‘natural’ gas, light crude, heavy crude, and bitumous coal.
Comment: The Ukraine Academy of science threaten to sue Thomas Gold for not giving credit to the Ukraine scientists who wrote papers 60 years ago supporting the same theory that Thomas Gold was promoting, twenty years ago.
What was missing 15 years ago when we discussed this issue (do you remember) is unequivocal proof that massive amounts of CH4 are moving up from the core of the planet as it solidifies which there now is.
Analysis of human CO2 emission vs changes in atmospheric CO2 do not agree with the so-called Bern equation which was created to create CAGW.
The analysis indicates that humans caused no more than roughly 5% of the increase in atmospheric CO2. That is only possible if there is a massive unaccounted for source of CO2 continually entering the biosphere, it’s CH4.
This is important as CAGW is based on the fossil paradigm where there is minimum new entering CO2 the biosphere, as CO2 is recycled.
An example of the new observations is seismic analysis that shows there is three times more water moving into the mantel than is coming out from volcanoes. The solution to the water paradox is there is massive amounts of CH4 coming into the biosphere. The source of the hydrogen for the missing water source and the missing CO2 source is the CH4 that is extruded from the core of the planet as it solidifies.
This is the hottest new discovery in science and is a new field for geology. I will start my own thread and explain the observations in question which are all from peer reviewed papers.
4. The Russian-Ukrainian framework The Russian tradition about biogenic/abiogenic oil formation is very old and both the frameworks were defended by their scientists. (Lomonosov, organic; Mendeleiev, abiogenic; and many others in historical times in both parties). More recently Elansky (1966) and the Ukrainian Chekaliuk (1967) proposed a HP/HT mechanism of oil formation starting from mineral carbon (CO2), hydrogen and methane. These chemical reactions are argued to happen in the mantle during serpentinization in presence of magnetite. Today Kitchka (2004) is proponent of a model of oil and gas acumulation that occurs by slow vertical migration and coalescence of HCs fluid inclusions through a fractured lithosphere and crust. Porfir’ev in its review of 1974 explained most arguments against the organic theory and he presents the history and reasons – with the limitations of the level of scientific research
David, you cherry picked your helium quote. Why?
A natural gas source must contain more than 0.3% helium for it to be commercially viable for helium removal.
To get 0.3% helium there must be concentrated uranium below the CH4 reservoir. Why is there concentrated uranium deposits below CH4 reservoirs?
Why is there uranium in heavy oils and in bitumous coal?
Where is Natural Gas Rich in Helium?
Most unprocessed natural gas contains at least trace amounts of helium. Very few natural gas fields contain enough to justify a helium recovery process. A natural gas source must contain at least 0.3% helium to be considered as a potential helium source.
In 2010, all of the natural gas processed for helium in the United States came from fields in Colorado, Kansas, Oklahoma, Texas, Utah, and Wyoming as shown on the accompanying map. The Hugoton Field in Oklahoma, Kansas and Texas; the Panoma Field in Kansas; the Keyes Field in Oklahoma; the Panhandle West and Cliffside Fields in Texas, and the Riley Ridge Field in Wyoming account for most of the helium production in the United States. 
Seismic study reveals 3 times more water dragged into Earth’s interior
“If other old, cold subducting slabs contain similarly thick layers of hydrous mantle, then estimates of the global water flux into the mantle at depths greater than 60 miles must be increased by a factor of about three,” Wiens said.
And for water in the Earth, what goes down must come up. Sea levels have remained relatively stable over geologic time, varying by less than 1,000 ft. This means that all of the water that is going down into the Earth at subduction zones must be coming back up somehow, and not continuously piling up inside the Earth.
Thomas Gold was a charlatan, the USSR disappeared.
Regarding Ghawar, since the field is entering a more mature phase of its life it may not be producible as high a rate because it simply doesn’t make economic sense.
Some forecasters of future production lump all the resources, and that can lead to really optimistic rate forecasts, because it just doesn’t make any sense to go for high rate. In some cases the development has to be phased, in others its better to time a very large project in parallel with pipelines, refinery modifications, oil upgrader construction, gas market development, etc.
What this means is that even if resources are in the ground, production may be stretched out for decades. And this can lead to future supply shortfalls. In some cases the country authorities may be trying to stretch the oil industry lifetime (one example of a country which manages development to stretch the industry life is Angola, one which is starting to feel sorry it didn’t is Trinidad and Tobago). Thus the Ghawar story by itself isn’t a big deal. But it may be a signal that they will not be increasing their capacity and this will lead to higher prices. And higher prices are badly needed for the “shale” developers because the current prices won’t justify sustaining rates after 2030. So in a sense this is good news for Texas.
For those younger people who might not get the picture of the iconic-commercial caveman, here’s the context:
I should have included the video in the post. I’ll add it in.
It always griped me that the “Cavemen” didn’t live in caves.
That’s just where the cave bears ate them… 😉
Then how come the ‘cavemmen’ always wear bear-skin? 🤔
I ceased listening to anything Bloomberg (the org) had to say when they started botching tech reporting in the early 2000s.
They’re a joke now, and so is Forbes. It’s almost depressing.
With Forbes, it all depends on the author. Jude Clemente’s oil & gas articles are generally exceptional.
Thank you for the commentary and interpretation. It is greatly appreciated.
I’m easily triggered by Bloomberg idiot-journalists… 😎
I also want to thank you for your perspectives as someone working in the field. When I read the article today I was left with questions. You have answered them.
Most of the credit goes to the Investing.com guy. His article cued me in on what I needed to look for.
Remember the USA had a reserve life index of 10 years for thirty years.
Quite a bit of research wouldn’t save their bacon. If you don’t have sufficient domain specific knowledge, you won’t understand what you’re reading.
A few isolated facts can be spun into complete crap. A chaplain I knew used to tell a story to his high school students.
Yeah… “You can’t fix stupid”… To quote the great Ron White… 😉
I know absolutely nothing about the oil industry.
But if they’re that certain about a maximum capacity of 3.8 million BPD, my first impression would be that its a limitation of their equipment, not the amount of oil available in the ground.
You started off correct.
Then what’s wrong with that impression?
If its not an issue of only so much oil being able to flow through the pipes, and its not, as your article says, that they are running out of oil, then why can’t they produce any more than that?
There is not an infinite volume of oil in Ghawar. The original oil in place (OOIP) was probably around 180 billion barrels. With secondary and tertiary recovery methods, 60-80% of that oil might be recovered (108-144 billion bbl). It’s produced over 65 billion barrels, about half of the recoverable oil. The current proved reserves are about 48 billion bbl. Proved reserves are the volume that can be expected to be produced at >90% probability under current economic and technical conditions. More pipes won’t put more oil in the ground.
The field should be in decline. However, it will be a very slow decline. The bond prospectus doesn’t say anything about what its current production is. The maximum rate the field ever achieved was a bit over 5 million bbl/d.
From the Aramco bond prospectus and quoted in my post…
The key phrase is “during any future planning period.” The 3.8 mmbpd is the rate they are assuring investors that Ghawar could be surged to over the foreseeable future. They aren’t saying anything about the current production rate.
Also from my post:
From the bond prospectus:
They don’t say what the current rate is. In 2018, Saudi Arabia averaged 10.4 million bbl/d of crude oil production, with total petroleum liquids averaging 12.4 million bbl/d. If Ghawar still accounts for half of Aramco’s oil production, it’s making about 5 million bbl/d. If the MSC numbers linearly correlate to current production, it’s currently producing about 3.3 million bbl/d.
A decline from 5 million to 3.3 million bbl/d since 2004 does not reflect a field in “serious decline.” That would reflect about a 2.7% decline rate.
At this decline rate Ghawar will still be producing over 1 million bbl/d in 2060. Again, from my post:
There isn’t a reply option on your response.
I never suggested that the supply was infinite, nor did I say anything about their current production.
I said that the figure they provided sounds like its the most that their equipment can do.
The heavier the crude, the more pressure it puts on their recovery systems.
And while I don’t know how the physics of those systems operate, or the geological challenges surrounding the recovery of oil, I DO understand the role that pressure plays in those systems, because I make the pressure relief valves for that industry.
There may be plenty of oil in the ground to be had, but upgrading their equipment to be able to produce it at a faster rate then that, isn’t economically practical.
An oil field’s production capacity can be limited by surface equipment, the pipelines, the well capacity, the reservoir capacity to produce without causing damage or hurting the field economic value by reducing reserves, or producing them at the wrong time. Given what we see, a prudent operator will be trending towards optimization of economics with a long term price deck which gets to $120 per barrel in today’s dollars in about 20 years. Some may say a bit less, some more. The timing can also vary. But the oil is getting harder to extract, we need more money to justify producing it, we are seeing that exploration doesn’t find oil to replace what’s being produced, and there are physical limits to what we can do.
And as you may imagine, the oil in the ground as well as pressure, rock quality, water and gas rate, and other technical/economic factors limit what can be done. We are not pumping oil from caves, it’s a bit more complicated than that.
Yep… And Saudi Arabia’s MSC requirements present a unique challenge to Aramco.
So much of the media – and this includes Bloomberg – seems to just assume that simply because they publish something it must be correct. And it almost never is completely correct! All the other outlets freely quote each other without question or even checking with knowledgeable sources – and the meme continues. [ref your comment that Wikipedia already used the Bloomberg info as if it were correct].
It seems to be a constant that crosses all party and political lines.
It’s even worse than that… Bloomberg News assumes that Bloomberg New Energy Finance Unicorn Fantasies are reality.
There are oil fields and there are refilling oils fields.
How much oil there is in a ‘reserve’ depends if is one of the refilling oil fields.
The Russian have reported the same phenomena where the oil field in question is refilling with lighter oil.
“Oil Fields Are Refilling…
Naturally – Sometimes Rapidly
There Are More Oil Seeps Than All The Tankers On Earth
Deep underwater, and deeper underground, scientists see surprising hints that gas and oil deposits can be replenished, filling up again, sometimes rapidly.
Although it sounds too good to be true, increasing evidence from the Gulf of Mexico suggests that some old oil fields are being refilled by petroleum surging up from deep below, scientists report. That may mean that current estimates of oil and gas abundance are far too low.
Recent measurements in a major oil field show “that the fluids were changing over time; that very light oil and gas were being injected from below, even as the producing [oil pumping] was going on,” said chemical oceanographer Mahlon “Chuck” Kennicutt. “They are refilling as we speak. But whether this is a worldwide phenomenon, we don’t know.”
Also not known, Kennicutt said, is whether the injection of new oil from deeper strata is of any economic significance, whether there will be enough to be exploitable. The discovery was unexpected, and it is still “somewhat controversial” within the oil industry.
The first sketchy evidence of this emerged in 1984, when Kennicutt and colleagues from Texas A&M University were in the Gulf of Mexico trying to understand a phenomenon called “seeps,” areas on the seafloor where sometimes large amounts of oil and gas escape through natural fissures.
The difference, Kennicutt said, is that the animals living around cold seeps live on methane and oil, while the creatures growing near hot water vents exploit sulfur compounds in the hot water.
The discovery of abundant life where scientists expected a deserted seafloor also suggested that the seeps are a long-duration phenomenon. Indeed, the clams are thought to be about 100 years old, and the tube worms may live as long as 600 years, or more, Kennicutt said.
Analysis of the ancient oil that seems to be coming up from deep below in the Gulf of Mexico suggests that the flow of new oil “is coming from deeper, hotter formations” and is not simply a lateral inflow from the old deposits that surround existing oil fields, she said. The chemical composition of the migrating oil also indicates it is being driven upward and is being altered by highly pressurized gases squeezing up from below.”
Beyond not even wrong. There isn’t even a definable point at which you exited reality.
“Analysis of the ancient oil that seems to be coming up from deep below in the Gulf of Mexico suggests that the flow of new oil “is coming from deeper, hotter formations” and is not simply a lateral inflow from the old deposits that surround existing oil fields, she said.”
That’s one theory to explain the phenomenon of ever-expanding oil and gas reserves (in the aggregate).
Another is the improvement of the extraction technologies and the increase in the number of formations in production.
Also, not much is known about many formations because of zealous environmentalism (versus conservationism).
This is a link to Congressional Research Service U.S. Fossil Fuel Resources: Terminology, Reporting, and Summary which, though a decade old, is a useful reference: https://www.epw.senate.gov/public/_cache/files/f/7/f7bd7b77-ba50-48c2-a635-220d7cf8c519/01AFD79733D77F24A71FEF9DAFCCB056.crs-updatedreport.pdf
It boils down to the rules regarding the booking of proved reserves, particularly for publicly traded companies.
For the US and the World, the paper gives concise meanings to “Proved reserves,” “Reserves,” “Reserves appreciation,” “Resources,” “Undiscovered resources,” “Undiscovered technically recoverable resources (UTRR),” “Undiscovered economically recoverable resources (UERR),” and “Unproved reserves.”
This chart from the Society of Petroleum Engineers sums up the key points…
In the US. “proved reserves” are the 1P number. This is the minimum volume of oil expected to be produced from a reservoir (>90% probability). Proved reserves go up all of the time without additional drilling because well performance converts 2P (50% probability) and some 3P (>10% probability) into 1P. Changing economic conditions can also move contingent resources into the 1P category.
As long as proved reserves and undiscovered resource potential remain steady or rise, each barrel of oil produced pushes Peak Oil further off into the future.
Most reserve additions don’t come from new discoveries. They come from reservoir management and field development operations.
Ghawar oil field was discovered in 1948. When first discovered, the estimated ultimate recovery (EUR) was in the neighborhood of 60 Bbbl. It has already produced over 65 Bbbl and it is estimated to have nearly 50 Bbbl remaining (EUR ~110 Bbbl). Half of Ghawar’s EUR was recognized at its discovery. The other half will be the result of field development and reservoir management.
It depends on the company, the country, and the flavor du jour. I’ve worked in countries where we kept reserve estimates for internal purposes with up to 12 different classes, we kept SEC reserves, and country reserves using the methods required by host country. The figures were different for the same field. The SEC had what we considered the most outdated methods, which they improved after the Shell screw up with a North Sea gas field which led to a huge number of audits.
In Venezuela the methods used in the Chavez years the reserves were really inflated (they are still inflated but BP keeps using them in their yearly review). And those reserves were supposedly audited by *prestigious engineering consultants*.
Very true. I generally assume that NOC proved reserves are 2P or 3P numbers.
However, the D&M audit of Aramco appears to have conformed to SEC standards. I think Aramco is serious about being taken seriously.
“Maybe do a little research”
Isn’t that what Dr. Ridd got the sack for?
Anyway, I read some years back that that North Sea oil production had fallen ~9% from the 1970’s volume which was expected by all experts. I read very recently, and I can’t recall where, that production of the field had not dropped and was steady. I have never been able to find reliable information about any of this.
I am a geophysicist and former exploration director for a large independent oil company. At one time I had the top web page on Ghawar on the internet and have studied this field extensively. At one time, I was in charge of reservoir simulation for my company. Every seminar and meeting I went to I talked to people who had worked Ghawar doing reservoir simulations. Absolutely everyone of them said the field didn’t have the reserves people thought it did in the West. In 1996 at the SEG convention, a Saudi Aramco employee gave a paper showing the water level for northern Ghawar and it was nearly at the crest of the field. Yes, the southern part of Ghawar had less permeable and porous rocks than the north and that was developed in a drilling mania in the first decade of this century. I for one do not think you are correct about Ghawar not declining fast. One guy told me that they had drilled a well for a core below the water level to see how much residual oil was left in northern Ghawar. Because of the vugular nature of the rock, there was only about 10% residual oil saturation. I for one find the Bloomberg article consistent with everything I know about Ghawar. I think Ghawar’s problem is why the Saudi’s were unable to ramp up production fast enough to kill off shale in 2014–go look at their production and it gradually rises from something like 9.5 million a day to 10.5 a day over a period of a year or so. That is my recollection of that curve. There was no step function in Saudi production.
D&M just audited Aramco’s proved reserves. The Bloomberg article isn’t even wrong.
The OOIP can easily be calculated from data that were publicly available before Aramco was fully nationalized.
Water flooding boosted recovery to about 50%. CO2 will likely push it to 80% This yields an EUR consistent with Ghawar’s current proved reserves plus past production.
Ghawar was producing at a 50% water cut as recently as 2004. It will still be producing a lot of oil at a 90% water cut.
William, you really need to study petroleum geology and, if you receive passing grade, then come back to finish your conversation.
My wife worked as a carbonate reservoir specialist on the Arab-D in Ghawar and various fields for both Aramco in Saudi Arabia and Aramco partner, Exxon Research. It is a supremely difficult reservoir to estimate production or reserves. On one hand, there are large leached corals present. Early production, flowing wells through 9 5/8″ casing, allowed early water encroachment through these mega-pores, giving the impression of early water-out and causing some dificulties in water management later in production.
One the end of the porosity spectrum, the enormous oil column has pushed oil into all sorts of microporosity, to the point that individual ooids have oil saturation in micropores. Some of this oil may come out as pressures drop, some won’t, but the oil satuation analysis from well log data yields deceptive results. Aramco has done a good job of managing this complex and difficult field.
Anyone who looks at the little bit of data available and publishes a conclusion (and many have), is as Dave Middleton would say, full of schist.
The thing is that a lot of the reservoir and petrophysical data have been available since the early 1980’s. The Arab-D structure map from Levorsen’s 1956 petroleum geology textbook is not terribly different from modern day 3d seismic maps.
The biggest secret is that there weren’t any real secrets.
Sure, but a structure map won’t tell you much about differential water encroachment. I’m referring to guys like Kenneth Deffeyes, who got a few thin sections from a Saudi student, and claimed he could tell from some dolomitized porous zones that water-out was imminent. Or Jean Laherrère, who claimed the water injection wells were like “a sword of Damocles hanging over the field”
The production methods and porosity types lead many to look at the data and predict early water-out. They have balanced production rates and water break through, and the dire predictions didn’t come true.
The dire predictions didn’t come true because Aramco is competently managing the reservoir and maximizing the recovery from the largest conventional reservoir on Earth.
Lol, you and Dave are not the first folk to say I am full of schist. You have to stand at the end of a long line of folk. I would point out that A. M. Afifi in his Distinguished lecture for AAPG said that Ghawar was producing from 4.6 to 5.2 million bbl/day during the 1993-2003 interval. see https://www.geoexpro.com/articles/2010/04/the-king-of-giant-fields
If the max rate of production today is 3.8 million per day, that is around a 25% decline from 15 years ago. Talk about micrporous saturation (most of which will never see the surface tank) really pales in comparison to the data we have on the actual number of barrels produced in the past vs what is said to be the maximum possible production today. I will stand on the schist and on my position on this issue.
I guess I am a bit surprised that yall think a 75 year old field wouldn’t have problems producing at earlier rates. Anyway, as I said, I will stand on the my schist.
A 25% decline over 14 years is less than a 2% decline rate.
Lol, you and Dave are not the first folk to say I am full of schist
Perhaps there’s a reason for that…..
He’s not really full of schist. He’s just arguing against a point I never made.
I don’t know, David, arguing against non-existent points sounds pretty close to being full of schist to me.
The 3.8mpd figure is not the maximum or even current production rate. It is the rate they are legally required to be able to set and maintain for at least a year, if required. It is almost certainly a conservative figure. You can bet they have a hedge there, such that if oil prices were to go up, they could increase rates beyond 3.8mpd. It’s possible that 25% decline you quote is even less, making the yearly decline pretty slim compare to other fields.
Ghawar could currently be producing at, above or below that number… It probably should be producing significantly less than 5 mmbpd. If Ghawar was exhibiting a 25% decline rate, it would already be gone.
If the max rate of production today is 3.8 million per day
As pointed out by several other posters, it’s not, so everything you said after that is moot.
Just a note to correct a couple of items.
1. The post says “The MSC rate is more of a minimum rather than a maximum”. (Maximum Sustainable Capacity) means just that. Each field is assigned an MSC on the basis of its maximum capability. There is also a factor for each field that defines the total field actual capacity, which is somewhat greater than the MSC. This is used to allow workovers and normal downtime for maintenance as needed. These factors are different for each field depending on operational history.If there is a shift in demand for a certain crude type (Aramco produces several different grades of crude) there could be a project defined to provide an “Increment” which will add MSC to the applicable field. Or if there is a new field development, that field will contribute its MSC to the mix.
2. RichVS’s comment was correct years ago. I retired from Aramco 9 years ago after working for them for 15 years. There are now several fields producing with artificial lift systems. Electric submersible pump systems are now operating in offshore and onshore fields. Some of this is due to increasing MSC (Abu Sa’fah offshore field) and some is due to declining reservoir pressure in poorly naturally supported regions (North Safaniyah). There was also an onshore increment from several older fields requiring artificial lift to provide additional MSC.
MSC is related to the maximum spare capacity. It has very little to do with maximum or actual production rate. It’s the guaranteed maximum production rate over the planning timeline. *Guaranteed* maximum capacity is actually a minimum production capacity.
An Aramco engineer told me in 1978 they had just started pumping and injection. The Saudis wer opposed as a point of pride “we don’t pump our wells, they flow”
So who benefits most, in the short term oil-trading markets, from the release of this information?
Investors benefit from the information. Speculators may or may not benefit from media misinformation
You invest in a field 40 years old and with bad salt water intrusion problems, you are a fool. Let the Arabs sell it so some other schmo.
Wrong in every way possible.
You can pump as much salt water from that field as you want, but they have been running pipes all over for years to get around the salt water intrusion. At 40 years, it is dead and production can collapse quickly. This is why the Saudis are selling it. Kind of like buying a dead camel at a bargain price.
They’ve been flooding the reservoir with water for decades to flush the oil out. The Arab-D carbonate is a phenomenal water-drive reservoir. It would be economic above a 90% water cut.
The water flood took it from a ~30% primary recovery to a ~50% secondary recovery. CO2 injection will probably push it to an 80% tertiary recovery of the oil-in-place.
They are not selling it. They are selling debt and to do that they have to provide very credible documentation that they can service the debt.
More clarifications necessary
1. Doug – The first artificial lift pilots for pumping wells were done in the mid and late “90s. Not sure what your engineer friend was referring to. I was the lead production engineer for several pilot projects. They were in 2 offshore fields (Abu Sa’fah and Berri) and in “production challenged” areas of the Ghawar field (in Uthmaniyah and Haradh)
2. David – The determination of the total required “field capacity” the responsible reservoir and production engineering folks take the MSC for the field and divide by the operating factor for that specific field. This is the production capacity for the field. The well by well design rates are determined by the operating parameters determined by the reservoir engineers to minimize reservoir damage and drain the reservoir at an overall target parameter, whether this is % depletion per year, or a target reservoir pressure (where there is pressure support from bottom water-aquifers), etc. The individual target well rates are added up to determine “existing well capacity” for the field. If there are projected shortfalls, then there will typically be development drilling projects developed. These are accomplished through Aramco’s Maintain Potential Projects funding, which are performed on a shorter fuse than a grass roots project. Every year at budget time, these evaluations are done to ensure that MSC requirements are met. For example, when I was working as a Field Development Engineer on the northern offshore fields, the Safaniyah field had an MSC of 1.1 MMBbl/d. It had an operating factor of .95 and a field (total well) capacity of approx. 1.16 MMBbl/d. (note – MM is shorthand for Million). Safaniyah has one central GOSP (Gas/Oil Separator Plant – plus water separation also) which has to be designed to the field capacity for total oil, water, and gas production, which is roughly 20% over MSC.
I disagree with your characterization. (Respectfully, of course.)
MSC as defined by Saudi Arabia is the maximum capacity over “any future planning period”.
The actual current production could be more or less than the MSC over “any future planning period”.
Brian–Thanks for your input. Nice to have so much expertice here. I never worked over there, though my wife did. In 1978 they flew me down to Houston to talk about working on a project. One of the guys I met was the head of Aramco engineering, who told me they were looking into doing some pressure maintenace injecting treated sea water and he related the Saudi opposition. Sounds like they didn’t get the ok to start it until later.
David – To clarify – I disagree with your characterization of MSC. I strongly agree with your comments on the quality and longevity of the Saudi Oilfields. I also worked on development of the Saudi offshore gas fields. Unfortunately for the Saudis, these fields were unlike those in offshore Qatar. They were extremely lean with no liquid hydrocarbons (one field had nothing heavier than C3.) What was jaw dropping was the reservoir quality. Well design rates were 500 MMSCF/d, Preliminary flowline design rates were 350 MMSCF/d. Aramco were developing these fields for fuel gas in the Kingdom, by the authority of the Oil Ministry, thereby displacing crude as a fuel in some applications.
The key point about MSC is that it’s over “any future planning period”
I think I see that some people are understanding the term MSC (maximum sustainable capacity) as if it were additional oil production that Saudi Arabia could turn on at the flip of a switch. The problem with that view is that the Saudi’s have almost always stated that they had a 12 million bbl/day total capacity. They always produced less oil than their maximum capacity but, they also claimed that they could ramp up to 12 million bbl/day quickly. From ArabNews:
“With the Kingdom raising production by nearly half a million barrels per day in just one month, this is proof that to meet market demands, Saudi Arabia can reach a 12 million bpd target at a rapid pace.” http://www.arabnews.com/node/1354181
Further proof that MSC does not mean ‘spare unutilized capacity’ comes from the Saudi Prospectus itself. On page B-2 they define MSC as:
“The average maximum number of barrels per day of crude oil that can be produced for one year during any future planning period, after taking into account all planned capital expenditures and maintenance, repair and operating costs, and after being given three months to make operational adjustments.” https://www.rns-pdf.londonstockexchange.com/rns/6727U_1-2019-4-1.pdf
Notice that 12 million barrel per day number. It is important to understanding what the 3.8 million barrel per day MSC the Saudi Bond prospectus has for Ghawar. Bloomberg understood the table on page 88 of the Saudi bond Prospectus as being the maximum production they could get from the field. Mr. Middleton believes, as far as I can tell that it is spare capacity and Ghawar is not in serious decline. Let’s think about the implications of Dave’s view. First, if this is really spare capacity as in ADDITIONAL oil production that could be turned on by the flip of a switch, then this would require that the Saudi’s actually have a 22-24 million barrel maximum production capacity–something they have never claimed to have. It would mean that they drilled twice as many wells as they actually produce. No retail store would build and stock a 100 stores only to open 50 of them. Similarly no oil company is going to drill twice as many wells as they intend to produce. So, the key to understanding table 88 is the 12 million bbl/day total. That is Saudi Arabia’s TOTAL maximum output for each field. Below is the table reproduced in part. Below is the last column of the table on page 88 of the prospectus.
Shaybah ………….. 1.000
Khurais ………..,… 1.450
Safaniyah ………… 1.300
Zuluf ………….,,,… 0.825
Other …………,,…. 3.625
Total …………,,… 12.000
This is clearly an accounting of where their maximum output of 12 million bbl/day would come from if they had to ramp up to that level of production. This, though means that it is highly likely that Ghawar is producing LESS than 3.8 million per day because the Saudi’s are only producing in the neighborhood of 9.5 to 10 million bbl/day. They are NOT at full output capacity.
From the above, Bloomberg is absolutely correct that Ghawar is producing somewhere around 3.8 million bbl/day today. Ghawar peaked at 5.7 million bbl/day in 1981 and was in the 5 million bbl/day as late as 2003, but now, production has dropped by 25% or so.
I don’t want to be argumentative but Ghawar is in serious decline after 68 years of production.
One further note, I don’t believe they can actually produce 12 million per day. If they could I think they would have done so in 2014 to kill the shale play. They couldn’t raise production fast enough to kill it off.
I did not say that MSC *was* spare capacity. I said it was *related* to spare capacity. From Aramco prospectus and quoted in my post…
The key phrase is “during any future planning period.” The 3.8 mmbpd is the rate they are assuring investors that Ghawar could be surged to over the foreseeable future. They aren’t saying anything about the current production rate. Also from my post:
From the bond prospectus:
In 2018, Saudi Arabia averaged 10.4 million bbl/d of crude oil production, with total petroleum liquids averaging 12.4 million bbl/d. If Ghawar still accounts for half of Aramco’s oil production, it’s making about 5 million bbl/d. They don’t say what the current rate is. If the MSC numbers linearly correlate to current production, it’s currently producing about 3.3 million bbl/d.
A decline from 5 million to 3.3 million bbl/d since 2004 does not reflect a field in “serious decline.” That would reflect about a 2.7% decline rate.
At this decline rate Ghawar will still be producing over 1 million bbl/d in 2060. Again, from my post:
in the future, if you’re going to argue against something I post, please quote the exact words you are arguing against.
I probably shouldn’t get involved, but…
“If Ghawar still accounts for half of Aramco’s oil production, it’s making about 5 million bbl/d.”
But the part that you quoted doesn’t say that Ghawar “still accounts for half of Aramco’s oil production.” It says about Ghawar:
“It has accounted for more than half of the total cumulative crude oil production in the Kingdom…”
So it’s talking about cumulative production of Ghawar, not current production of Ghawar.
If Ghawar accounted for half of Saudi Arabia’s cumulative crude oil production, it would have, on average, accounted for half of their daily production. But, clearly there would have been periods when it was more or less than half.
Not a lot of detailed field-level production data have been published. The most recent are from 1993-2003…
This was originally in an AAPG paper and versions of it have appeared in multiple presentations.
The main points of this post were:
1) The bond prospectus citation of a current MSC of 3.8 mmbpd doesn’t tell us much about Ghawar’s current production rate. This is due to Aramco’s definition of MSC.
2) Even if Ghawar was only producing 3.8 mmbpd, it wouldn’t be indicative of “the biggest Saudi oil field is fading faster than anyone guessed.”
I don’t think it matters… to the Saudis, anyway.
they ae busy preparing and investing for the post oil era in Saudi Arabia
I would have to agree with you there Griff. But, that does not mean they have no oil.
100 years down the road.
If it didn’t matter to the Saudis, why are they collateralizing a bond issue with their oil production?
But we only have 12 years to go … they shouldn’t be pumping anything.
Meanwhile we just passed thru 100 million barrels of oil a day, reality was never a strong suit of left or Griff.
David. Glen Morton’s post on the MSC discussion has pretty much nailed it.
The MSC for any field is the MAXIMUM average calendar day production allowed by the field facility design and the well capacity. The production capacity for a field is referred to by operating day and is simply MSC divided by the operating factor, which us a historical reflection of the field efficiency. Typical operating factors range from 0.9 to 0.95. Within Aramco the MSC is expressed as MBCD (Thousands of Barrels of oil per CALENDAR Day – average monthly maximum production). The maximum oil production rate is expressed as MBOD (Thousands of Barrels per OPERATING Day). The MSC forecasts are used to design facility additions/modifications and to plan drilling programs in cases where the MSC is holding or increasing with time. MSC will also be allowed to decline with time in some cases. This can happen in mature fields which have no immediate lower cost development options. It can also happen where there is an over abundance of a particular crude grade. It doesn’t necessarily mean that any specific field is “on the ropes”.
Both well capacity (with regard to minimizing well and reservoir damage) and facility capacity must be maintained in order to produce at MSC. Onshore fields have a 1 year requirement for sustaining the MSC; offshore fields have a 2 year requirement.
Saudi Arabia defines MSC a bit differently than most people do.
From the Aramco prospectus, page 8…
Aramco’s MSC is a politically imposed number. 12.00 million bbl/d is not the sort of number that results purely from operational and production constraints. The Kingdom can increase it or decrease it at their discretion.
Ghawar’s MSC of 3.8 million bbl/d is what they are assuring investors that it can produce “for one year during any future planning period.” It could be producing more or less than the MSC. If it still accounts for half of Saudi Arabia’s production, it is currently producing more than the MSC. If it’s current production is in proportion to the MSC, it’s producing less than the MSC. Since it has produced more than half of its likely EUR, prdocuction rates have probably dropped below 5 million bbl/d – I stated this in the post.
The odds are that Ghawar is currently producing around 3.3 million bbl/d, which is not indicative of a field in “serious decline” and not even close to “fading faster than anyone guessed.” This would reflect a 2-3% decline rate since 2004.
Aramco’s MSC is a politically imposed number. 12.00 million bbl/d is not the sort of number that results purely from operational and production constraints. The Kingdom can increase it or decrease it at their discretion. From 2011-2016, they increased it from 10 to 12 million bbl/d and they are required by law to maintain that level until the Kingdom says otherwise…
David. Maintenance of MSC must reflect the reservoir, well, and facility constraints. Additions to MSC are typically resulting from new field increments. They are not “pulled out of the air”. The increments may be in an existing field, a brand new discovery, or an old dormant field. The MSC additions between 2011 and 2016 which you pointed to were a result of developing older dormant fields (e.g. Manifa, Abu Hadriyah, Fadhili, Khursaniya, and Khurais. The Oil Ministry does not make unilateral decisions on MSC without consultion with Aramco. Aramco do not make the decision to alter MSC. MSC is a hard number backed by field capability. This is the way Aramco and the Oil Ministry conduct business.
You bolded the statement regarding the one year capability for the company to meet the MSC rate. In offshore fields, this is a two year window, as the “Maintain Potential” (I mentioned this in a previous post) planning cycle for offshore fields is one year longer than for the onshore fields. If the Oil Ministry desires to keep production rates from an entity at MSC levels for a longer period, then Maintain Potential drilling and facility requirements are invoked to offset the decline rate and maintain the relationship between field production capacity and MSC. (also discussed in an earlier post)
I know no other jurisdiction that operates in the manner of Aramco. Most places will produce at their maximum rates (with associated good engineering and production practice) whereas Aramco normally does not produce at maximum rates. Keeping production capacity in reserve has been profitable for them in the past (e.g. during lead up to the Gulf War). In fact, when I was still employed by Aramco, we had done an analysis showing that during periods where we produced at MSC rates, world crude prices were high (relative for the time frame). Saudi Arabia has used their excess capacity for political purposes in the past and will continue to do so. Based on the past, any increases in MSC are always implemented with Aramco and the oil ministry being on the same page when it comes to the production capability of the increment.
As to the production blips from Aramco in response to the shale revolution, I think that they have been effective in keeping the higher cost shale projects from gaining hold.
Based on my own experience at Aramco which were related to field facility development (for new and existing field increments as well as the Maintain Potential program), the MSC number was backed up by competent reservoir engineering, production engineering, facility engineering, and operational practices.
I’m sure that the MSC number is backed up “by competent reservoir engineering, production engineering, facility engineering, and operational practices”… But, unlike most companies, it is a number that’s dictated by the government.
They couldn’t publish an MSC of exactly 12.00 mmbpd in a public offering unless they could back it up. It’s just that this is a top-down calculation. The odds are that the actual achievable current MSC is higher than 12.00 mmbpd because they are assuring it “for one year during any future planning period.”
“I know no other jurisdiction that operates in the manner of Aramco. Most places will produce at their maximum rates (with associated good engineering and production practice) whereas Aramco normally does not produce at maximum rates”
Lest we forget, Saudi is a lynchpin producer in a Cartel. It’s called OPEC. They operate as swing producers to balance the physical market.
Of course, actual production rate is a political decision aimed at balancing physical supply and influencing prices
I am not familiar with your background, but I am going to guess you have experience in the oil industry, and likely geology. You strike me as someone who has presented material to executives of companies.
I noted one point I cannot reconcile:
“The New York Mercantile Exchange designates petroleum with less than 0.42% sulfur as sweet. Petroleum containing higher levels of sulfur is called sour crude oil.”
You said: “That would be H2S, not SO2 and most Saudi crude is “sweet”… it has a low sulfur content.”
Researching the sulfur content of Saudis oil has been frustrating, but I found a site that indicated the average sulfur content of the Ghawar field to be around 1.5% and the average for “Arab Oil” to be over 2% (by weight).
Can you reference a site that actually lists the sulfur content of Saudis oil fields? And is the definition of “Sweet Crude” the same as you are using? (contains less than 0.42% sulfur)
This information helps me to understand where the oil has to go to be refined. It isn’t just production fields that matter, but transportation routes to get crude to refineries, and then of course to get the refined products to markets.
I’ve been a geologist/geophysicist in the oil industry since 1981, mostly working the Gulf of Mexico. You are correct, the sulfur content is a little higher than I thought it was.
That’s what I get for talking off the top of my head.
Ah, thanks, this is just what I was looking for. 🙂
I actually had those data “right under my nose,” but I was working out the original oil in place, in which sulfur content doesn’t matter.
Some companies that are major marketers and traders make fuels type crude assays available as part of their marketing efforts.
Example below BP lists a number of grades that they are involved with commercially
However Aramco doesn’t do this as far as I’m aware.
Listing below is spot on from my memory. I’m an old/former downstreamer who was heavily involved in downstream optimization modeling most of my career
Arab Light crude
Some more basic info here
Pipelines also keep some basic data for their purposes
Aha!! Sorry for my vague response. Yes, in the late 70s/early 80s (well before my time in KSA) there were sea water injection projects in some areas of the Ghawar field. This was to supplement natural pressure maintenance in areas of the field with poor support.
I assumed you were referring to artificial lift projects – the installation of well equipment designed to increase production by dropping the bottom hole pressure in the wellbore.
Thanks for this discussion. There aren’t many topics on the Blog that I can contribute to as an actual informed technical guy. This was fun.
Regards to you too, Brian
Your contributions were great. My job is generating prospects… but I find that I learn more from operations people than just about any other group.
I’m working on another Ghawar post… I should finish it this weekend or early next week.