Peak Ghawar: A Peak Oiler’s Nightmare

Alternate title:

No… “The biggest Saudi oil field is [NOT] fading faster than anyone guessed”… Part Trois: Why Peak Oil Is Irrelevant and the Perpetually Refilling Abiotic Oil Field Is Abject Nonsense

Guest reservoir geology by David Middleton

Saudi Aramco’s recent bond prospectus has generated a lot of media buzz, particularly regarding the production from Ghawar, the largest oil field in the world. Reaction has ranged from “The biggest Saudi oil field is fading faster than anyone guessed,” (not even wrong) to more subdued reactions from Ellen Wald and Robert Rapier, that the prospectus doesn’t really tell us much Ghawar’s decline rate. One thing that the bond prospectus did do, is to paint a picture of the most profitable company in the world and one that is serious when it says it will produce the last barrel of oil ever produced on Earth.

How big is Ghawar? Has it peaked? Is it “fading faster than anyone guessed”? The answer to the first question is: FRACKING YUGE. The answer to the second question was not easily answerable before Saudi Aramco began the process of becoming a publicly traded company. The answer to the third question is: Of course not.

As Saudi Aramco proceeds towards a 2021 IPO, it has had to embrace transparency. This involved an audit of the proved reserves in their largest fields, comprising about 80% of the company’s value. The audit was conducted by the highly respected DeGolyer and MacNaughton firm (D&M). The audit actually determined that the proved reserves are slightly larger than Aramco’s internal estimate.

This is from D&M’s certification letter (Appendix-C in the bond prospectus):

Reserves estimated herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2017, but before December 31, 2077 (license limit). Net reserves are defined as that portion of the gross reserves attributable to the interests held by Saudi Arabian Oil Company after deducting interests held by others. Saudi Arabian Oil Company has represented that it holds 100 percent of the interests evaluated herein; therefore, net reserves are equivalent to gross reserves for the purposes of this report.

Saudi Arabian Oil Company has represented that it holds interests in certain properties onshore and offshore the Kingdom of Saudi Arabia. Proved reserves have been estimated for 77 reservoirs in 29 fields in this report.

[…]

Definition of Reserves
Estimates of proved reserves presented in this report have been prepared in accordance with the PRMS approved in March 2007 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. Only proved reserves have been evaluated for this report. The petroleum reserves are defined as follows:

Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.

Proved Reserves – Proved Reserves are those quantities of petroleum which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90-percent probability that the quantities actually recovered will equal or exceed the estimate.

[…]

Aramco bond prospectus, pages C-1 and C-3

A couple of important clues to Ghawar’s current production rate:

  • Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2017, but before December 31, 2077.
  • Proved Reserves are those quantities of petroleum which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward… If probabilistic methods are used, there should be at least a 90-percent probability that the quantities actually recovered will equal or exceed the estimate.

D&M’s proved reserve number for Ghawar was 48,254 million barrels of liquids (crude oil, condensate and natural gas liquids). That’s just a shade under 50 billion barrels to be produced from 2018-2077.

Ghawar: “The King of Giant Fields”

Discovered in 1948 and located some 200 km east of Riyadh, Ghawar has produced about five million barrels of oil per day in the past three decades. Last year, output from Ghawar accounted for 62.5% of Saudi Arabia’s crude production (about 8 MMbopd) and 6.25% of the world’s total oil production (about 80 MMbopd).

Sorkhabi 2010, “Ghawar: The King of Giant Fields”

Ghawar is “big”…

Figure 1. Ghawar relative to the State of Louisiana (Afifi, 2005)

Dr. Abdulkader Afifi described the geologic setting in his 2004 AAPG Distinguished Lecture…

Aramco initially discovered oil in Ghawar in 1948, based on surface mapping and shallow structure drilling. Ghawar is a large north-trending anticlinal structure, some 250 kilometers long and 30 kilometers wide. It is a drape fold over a basement horst, which grew initially during the Carboniferous Hercynian deformation and was reactivated episodically, particularly during the Late Cretaceous. In detail, the deep structure consists of several en echelon horst blocks that probably formed in response to right-lateral transpression. The bounding faults have throws exceeding 3000 feet at the Silurian level but terminate within the Triassic section. The episodic structural growth influenced sedimentation of the Permo-Carboniferous sandstone reservoirs, which onlap the structure and the Jurassic and Permian carbonate reservoirs, which accumulated in shoals above structural culminations.

The main oil reservoir is the Upper Jurassic Arab-D limestone, which improves upward from mudstone to skeletal-oolitic grainstone, reflecting successive upward-shoaling cycles. The excellent reservoir quality is due to the preservation of the primary porosity, the enhancement of permeability, and the presence of fractures in the deeper and tighter parts. The oil was sourced exclusively from Jurassic organic-rich mudstones and is effectively sealed beneath massive anhydrite. The general absence of faults at the Arab-D level maintained seal integrity. Current production is almost 5 million barrels per day under peripheral water injection. The southernmost part of the field remains under development, with a final increment of 300,000 barrels per day on stream in 2006.

Afifi, 2005

The structural/stratigraphic setting couldn’t have been better if it was designed for the purpose of becoming a super-giant oil field. The presence of a positive paleo-structure, episodic reactivation of uplift and buried fault system provided for a high-energy depostional environment, critical to the formation and preservation of carbonate porosity and provided pathways from the underlying prolific Silurian source rocks. The Jurassic Arab-D formation is covered by a thick sequence of anhydrite, forming a very effective seal.

Figure 2a. Ghawar Jurassic stratigraphy. Sorkhabi (2010)
Figure 2b. Ghawar Paleozoic stratigraphy. Sorkhabi (2010)
Figure 2c. Ghawar E-W Cross Section. Afifi (2005)

The Arab-D carbonate is an incredible reservoir, particularly the skeletal-oolitic grainstone.

Figure 3a. Ghawar Arab-D litho-facies. Afifi (2005)
Figure 3b. Ghawar Arab-D litho-facies. Afifi (2005)

Ghawar is subdivided into five segments: Ain Dar, Shedgum, Uthmaniyah, Hawiyah and Haradh.

Figure 4a. Arab-D structure map originally published in Levorsen 1954. Greg Kroft, Inc.

The 1954 structure map holds up pretty well today.

Figure 4b. 3d representation of Ghawar structure. Afifi (2005).

In 1980, Aramco published all of the data anyone would ever need to calculate the original oil in place (OOIP) for Ghawar:

Figure 5. Arab-D reservoir properties. Sorkhabi (2010)

I planimetered the areas of the five segments and then calculated to OOIP using this equation:

Figure 6. Basic volumetric equation. AAPG

This is what I came up with:

Figure 7. Ghawar OOIP.

About 183 billion barrels of oil. I also estimated approximate recoverable volumes:

OOIP   182,773,625,918 bbl
Primary Water Drive 40%     73,109,450,367 bbl
Secondary Waterflood EOR 50%     91,386,812,959 bbl
Tertiary CO2 injection EOR 60%  109,664,175,551 bbl

In order to estimate Ghawar’s current production rate, I needed three numbers:

  1. Original oil in place.
  2. Current proved reserves.
  3. Cumulative production

We have estimates of OOIP and proved reserves, but the cumulative production is a bit “fuzzy”.

Beydoun in his book (The Middle East, 1988) reports that Ghawar had produced 19 Bbo by 1979. According to an article on Ghawar in the AAPG Explorer (January 2005), the cumulative production from the field was 55 Bbo. The International Energy Agency in its 2008 World Energy Outlook states that the oil production from Ghawar reached 66 Bbo in 2007 and that the remaining reserves are 74 Bbo.

Data on Ghawar reported in the past issues of Oil & Gas Journal indicate that when Ghawar came on stream in 1951 it produced 126,000 bopd but production steadily rose with a major boost soon after the 1973 oil shock so that the field’s 1975 output was 4.2 MMbopd; this reached a maximum production of 5.7 MMbopd in 1981. From 1982-1990, the Saudis lowered their oil production for market considerations (most notably the oil crash of 1985) and thus Ghawar’s production was 2.5 to 3 MMbopd during that decade. A senior geologist with Saudi Aramco, A. M. Afifi, in his 2004 AAPG Distinguished Lecture, reported production values of 4.6-5.2 MMbopd for Ghawar from 1993 through 2003. These data indicate that 50-65% of Saudi Aramco’s oil production has traditionally come from Ghawar. Apparently, one half of Ghawar’s production (2.0 to 2.7 MMbopd) comes from the Ain Dar and Shedgum areas, while Uthmaniyah provides 1 MMbopd, and another million barrels or so comes from Hawiyah and Haradh combined.

Sorkhabi (2010)

For my estimate, I used the AAPG number of 55 billion bbl as the cumulative production through 2004. I then used the production data cited in Afifi (2005) as a starting point for a decline curve.

Figure 8. Saudi Arabia and Ghawar oil production. Crude = Crude oil and natural gas condensate, NGL = Natural Gas Liquids other than wellhead condensate, MSC = Maximum Sustained Capacity, Rpt. Ghawar = Published reports of Ghawar’s production rate, DCA = Decline Curve Analysis

The Aramco bond prospectus noted that Ghawar’s MSC (maximum sustained capacity) was 3.8 million barrels per day (bbl/d) in 2018. Based on Aramco’s definition of MSC, it’s difficult to determine if that is a current value or an average value over the Saudi planning period (which appears to be 50 years). A 2% decline rate, typical of giant oil fields (Höök et al, 2009), fits a current MCS of 3.8 million bbl/d. A 1% decline rate fits a long-term average MCS of 3.8 million bbl/d. Based on the cumulative production and proved reserves, a 2% decline rate seems likely.

A 2% decline rate would lead to Ghawar producing just over 100% of its proved reserves (1p) from 2018-2077 (50.7 billion bbl). Recall that proved reserves (1p) is a >90% probability volume. Proved + probable reserves (2p) is the most likely volume (>50%). 2p is always a little (or a lot) bigger than 1p. As far as I know, Aramco has not published a 2p volume.

A 2% decline rate would lead to a recovery of approximately 65% of the OOIP from 1951-2077.

People have often asked, “How could Saudi Arabia ever replace Ghawar, the largest oil field in the world?” They already have replaced it… and Ghawar is not “fading faster than anyone guessed.” It’s declining as gracefully as befits the world’s super-giant oil field.  Aramco plans on being able to produce 12 million bbl/d as for more than 50 years and they have the capacity to do so.

Figure 9. With a relatively minor contribution from probable reserves and proved reserve replacement, Aramco can produce 12 million bbl/d until at least 2060. Abdulbaqi & Saleri (2004).

The Peak Oiler’s Nightmare

Almost all petroleum reservoirs exhibit exponential decline curves. They don’t fall off of a Seneca Cliff into the Olduvai Gorge. In aggregate, regional and global oil production has and/or will follow the same pattern, because it is just the sum of the individual reservoirs. Hubbert’s logistic function is an approximation of this basic principle of reservoir depletion.

Reality…

Reality… I can do this for any field in the Gulf of Mexico because I have easy access to the production data. I could also do it for just about any oil reservoir on Earth; I just don’t have those data literally at my fingertips. EI 330 is just the biggest field on the shelf (<500′ water depth), almost 500 million bbl of oil and 1.9 TCF of gas from September 1972 through January 2019. The field averaged 820 8,200 bbl/d in 2018. A rate vs time plot would look very similar; however rate vs cumulative production is what matters. EI 330 has also been cited as an example of abiotic oil… ROTFLMFAO!!!

Peak Oiler Fantasy…

Fantasy.

About the author

David Middleton has 38 years of experience as a geophysicist and geologist in the oil & gas industry, including a six-year exile into management. The vast majority of his career has been spent working the Gulf of Mexico. He has been a member of the Society of Exploration Geophysicists since 1981 and the American Association of Petroleum Geologists since 2004.

A note on comments: Abiotic oil aficionados are more than welcome to waste their time posting gibberish, but they won’t waste any of mine. Peak Oiler’s are also welcome to babble about Seneca Cliffs and Olduvai Gorges… And that might just merit wasting some of my time.

References

Abdulbaqi, Mahmoud, M. & Nansen G. Saleri. Fifty-Year Crude Oil Supply Scenarios: Saudi Aramco’s Perspective. CSIS, Washington D.C. February 24, 2004.

Afifi, Abdulkader. (2005). Ghawar: The Anatomy of the World’s Largest Oil Field. Search and Discovery Article #20026 (2005). Adapted from AAPG Distinguished Lecture, 2004.

Bardi, Ugo. “The Seneca Effect.” The Seneca Effect, thesenecatrap.blogspot.com/.

Blas, Javier. “The Biggest Saudi Oil Field Is Fading Faster Than Anyone Guessed.” Yahoo! Finance, 3 Apr. 2019, finance.yahoo.com/news/biggest-saudi-oil-field-fading-113434887.html.

Croft, Greg. The Ghawar Oil Field, Saudi Arabia. Greg Croft Inc.
http://www.gregcroft.com/ghawar.ivnu

DiChristopher, Tom. “Saudi Arabia’s Massive Oil Reserves Total 268.5 Billion Barrels, Even Bigger than Previously Known.” CNBC, 9 Jan. 2019, www.cnbc.com/2019/01/09/saudi-arabias-massive-oil-reserves-grow-by-2point2-billion-barrels.html.

Höök, Mikael & Hirsch, Robert & Aleklett, Kjell. (2009). Giant oil field decline rates and their influence on world oil production. Energy Policy. 37. 2262-2272. 10.1016/j.enpol.2009.02.020.

Hubbert, M. King. “Nuclear Energy and the Fossil Fuels. Presented before the Spring Meeting of the Southern District, Division of Production, American Petroleum Institute, San Antonio, Texas, March 7-8-9, 1956.” Nuclear Energy and the Fossil Fuels. Presented before the Spring Meeting of the Southern District, Division of Production, American Petroleum Institute, San Antonio, Texas, March 7-8-9, 1956, 1956. https://debunkhouse.files.wordpress.com/2017/03/1956_hubbert.pdf

Levorsen, A. I. Geology of Petroleum. Freeman, 1954.

Middleton, David H. “No… ‘The Biggest Saudi Oil Field Is [NOT] Fading Faster than Anyone Guessed’…” Watts Up With That?, 5 Apr. 2019, wattsupwiththat.com/2019/04/04/no-the-biggest-saudi-oil-field-is-not-fading-faster-than-anyone-guessed/.

Middleton, David H. “Demand for Aramco Bond Offering Breaks Records… Tops $85B.” Watts Up With That?, 9 Apr. 2019, wattsupwiththat.com/2019/04/09/demand-for-aramco-bond-offering-break-records-tops-85b/.

Paraskova, Tsvetana. “Saudi Arabia: We’ll Pump The World’s Very Last Barrel Of Oil.” OilPrice.com, 23 Jan. 2019, oilprice.com/Energy/Crude-Oil/Saudi-Arabia-Well-Pump-The-Worlds-Very-Last-Barrel-Of-Oil.html.

Peak Oil. “The Seneca Cliff of Oil Production”. Exploring Hydrocarbon Depletion. June 7, 2016. https://peakoil.com/production/the-seneca-cliff-of-oil-production

Rapier, Robert. “The Permian Basin Is Now The World’s Top Oil Producer.” Forbes Magazine, 5 Apr. 2019, www.forbes.com/sites/rrapier/2019/04/05/the-permian-basin-is-now-the-worlds-top-oil-producer/.

Saudi Arabian Oil Company (Aramco). Global Medium Term Note Programme. Base Prospectus dated 1 April 2019.

Sorkhabi, Rasoul (2010) The King of Giant Fields. GeoExpro, vol. 7, no. 4 (January-February 2010), pp. 24-29). Published, 09/2010.

Wald, Ellen R. Investing.com. “What Saudi Aramco’s Bond Prospectus Reveals About Its Oil Reserves.” Investing.com, 4 Apr. 2019, www.investing.com/analysis/saudi-aramco-bond-prospectus-200403775.

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John Endicott
April 10, 2019 10:11 am

As always, David, That was a very informative read. Thanks.

R Shearer
Reply to  John Endicott
April 10, 2019 10:23 am

+ Agreed.

markl
April 10, 2019 10:43 am

But abiotic oil is such a warm fuzzy. Can’t I believe in it anyway? Or should I shift my fantasies to what we know is remaining and the fact that we’re still finding more oil? What about my great grandchildren? Will they be left with only a few hundred years of fossil fuels?

Archer
Reply to  markl
April 10, 2019 1:11 pm

The idea of rapidly re-filling oil fields is likely a fantasy based on the evidence.

However…

Given the abundance of hydrocarbons throughout the solar system (and the measured abundance of hydrocarbons in the spectra of distant nebulae), it is madness to believe that Earth is somehow uniquely the only place where hydrocarbons are primarily biogenic. Non-biogenic hydrocarbons are just not where we would expect them to be based on assumptions about biogenic hydrocarbon formation.I would not be the least surprised if relatively abundant oil eventually ends up being found just about everywhere.

Hocus Locus
Reply to  David Middleton
April 10, 2019 3:51 pm

They aren’t formed by biological processes. They are formed by thermogenic processes from material of biological origin.

What a simple revealing statement. I wished I had this in mind for countless replies over the years…

You win a “Subduction leads to Orogeny” T-Shirt.
Gwahar is small compared to Louisiana.
Pick on Delaware, everybody does.

Archer
Reply to  David Middleton
April 11, 2019 1:40 am

I do tend to mix up biotic and biogenic. Dyslexia.

I understand the conventional theory just fine, I simply find it unbelievable that earth alone is somehow exempt from the otherwise universal formation of primordial hydrocarbons. As tampatom pointed out, complex organics and hydrocarbons have been observed forming in deep space. They’re everywhere. But apparently just not here for some reason.

MarkW
Reply to  Archer
April 11, 2019 6:30 am

They did form here. However once plants started producing oxygen, whatever was left from the formation quickly oxidized.

Paul Milenkovic
Reply to  David Middleton
April 11, 2019 3:59 pm

What does J. F. Kenney flat-out not understand about the conventional theory, especially of oil formation?

Forget about abiotic origin for the moment. The question is by what thermal process do straight-chain alkanes form from whatever biological source material under conditions of the crust. His claim is that this major constituent of oil cannot form by an equilibrium thermodynamic process for the same reason diamonds don’t form there.

He nor me are claiming that the Fischer-Tropsch process takes place geologically. But, Fischer-Tropsch which takes place under conditions of pressure and temperature not representative of where Kenney claims oil forms, these are non-equilibrium processes as they are not run to completion if the more commercially synthetic #2 Diesel is what you want into instead of the less valuable methane.

Oil can still form from organics through the plate-tectonic conveyor, but the claim is that molecular weights greater than CH4 require mantle conditions for formation, just as diamonds do.

Yes, I know about the argument “how does the oil squeeze through the rocks up from the mantle”? But this doesn’t settle the argument as to from what source material (Kenney uses carbohydrates as a “straw-man” source, petroleum geo-chemists claim certain algae constituents as the source) and by what thermodynamic process does oil form in the crustal oil window?

Yes, I heard your argument that it “has to” come from the crustal oil window, but if we don’t know the chemical pathways, this is a major gap in human understanding. It also undermines the claim that the people who don’t accept this are unscientific cranks.

I rather people admit to the uncertainty in the science rather than make broad claims that the science is known, especially when it isn’t.

Paul Milenkovic
Reply to  Paul Milenkovic
April 11, 2019 7:05 pm

Kenney knows as much about the geothermal gradient as anyone else.

He claims, based on equilibrium thermodynamics that any heavier alkane than methane can only form under the extreme temperature and pressure of the mantle, much for the same reason that diamonds can only form there. There is that now semi-famous paper of how someone formed methane and higher alkanes in a diamond-anvil cell simulating mantle conditions, starting with water, iron ore and limestone. Calcium carbonate has an organic origin, doesn’t it?

If straight-chain hydrocarbons are found anywhere else than in the mantle, such as in crustal deposits in the “oil window” portion of the geothermal gradient or in the gas tank of my car, they are “metastable” there, just like the diamond in a ring someone is wearing.

The migration problem for diamonds is “solved” by the kimberlite “diamond pipe”, hypothesized to be a type of explosive eruption that no human has witnessed.
I get that there is a problem, a whole bunch of problems, of how mantle oil could migrate to the oil window where it won’t get cracked into methane and petcoke. But how did it form in the oil window when the thermodynamics say that it cannot by an equilibrium process?

One way to refute Kenney is his assertion that the conventional theory of oil formation starts with cellulose — material from vascular plants — from which he claims that under crustal conditions you can only form methane. Or coal. The most current version of conventional theory of oil formation is that you have to start with algae. There are papers suggesting that some algae, or organelles in algae, are much closer to oil than any tree or vegetable is. There is also what is called a serpentinization reaction involving some manner of fluid transport that facilitates non-equilibrium chemical reactions.

But tell me that his grasp of chemical thermodynamics is wrong?

TampaTom
Reply to  Archer
April 10, 2019 9:25 pm

Archer, I agree. In the link below is an image of a complex carbon based organic molecule — found in DEEP INTERSTELLAR SPACE.

Here is link to the research:

http://newatlas.com/organic-stardust-discovered/20310

The researchers have found that:

“not only are stars producing this complex matter on extremely short time scales of weeks, but they are also ejecting it into the general interstellar space in between stars.”

I am not an “abiotic” fan in the sense that oil is produced in the deep earth, but rather I am an “abiotic” fan in the sense that the supernovae stars produced massive amounts of unreduced complex carbon molecules and flung them into space when they exploded. The earth was blessed with huge quantities of this “molecular dust” in its original formation. I highly recommend to you the book The Deep Hot Biosphere by Thomas Gold,

http://www.amazon.com/s/ref=nb_sb_ss_i_1_13?url=search-alias%3Dstripbooks&field-keywords=the+deep+hot+biosphere+the+myth+of+fossil+fuels+by+thomas+gold&sprefix=the+deep+hot+

It is Gold’s premise that the vast, vast majority of hydrocarbon deposits of oil and gas and hard coal on earth are from hydrocarbons present in the original stellar accretions of space dust which amalgamated to become the earth. As such, these reserves are NOT biological in origin, the reserves are much more abundant than thought, are fully renewable, and virtually inexhaustible.

Thomas Gold is no dummy:

Thomas Gold is a member of the National Academy of Sciences, a Fellow of the Royal Society, and an Emeritus Professor of Physics at Cornell University. Regarded as one of the most creative and wide-ranging scientists of his generation, he has taught at Cambridge University and Harvard, and for 20 years was the Director of the Cornell Center for Radiophysics and Space Research.

I imagine it will take some time to get rid of the belief that oil and gas are “fossil” fuels and non-renewable.

Bob boder
April 10, 2019 10:45 am

David you are a national treasure!

April 10, 2019 10:51 am

Aramco’s proposed $10 billion bond issue is 10 times oversubscribed.

Neil Jordan
April 10, 2019 11:01 am

David: Re “I planimetered the areas of the five segments and then calculated to OOIP using this equation:” Was that a K&E compensating polar planimeter or equivalent, or have you gone over to the dark side with one of those battery-powered rolling things? Three traverses and divide the cumulative by three? Did you adjust for the tooth (roughness) of the paper and account for grease spots from the donut?

Neil Jordan
Reply to  David Middleton
April 10, 2019 11:31 am

Thank you. Bookmarked. But I still miss the coffee and donut while planimetering.

Reply to  Neil Jordan
April 10, 2019 10:33 pm

I learned to planimeter in 1966 when I started working for the Gas Department in the Alberta Oil and Gas Conservation Board. The next year they hired a young fellow that used to party on the weekend and often spent his noon hour lunch in the nearby hotel bar. One day I went by the work room and he was planimetering and he was shaking so bad he had trouble staying on the line. I informed the Chief Reservoir Engineer and after watching the fellow work he laughed and said not to worry, that the trainee was shaking on both sides of the thickness pay line and it should all even out. That was the last time he was assigned that job. He only lasted another couple of months since he had trouble coming getting to work on Mondays.

Javier
April 10, 2019 11:13 am

A Seneca cliff in oil is no longer fantasy.

Venezuela is displaying one for all to see.

http://peakoilbarrel.com/wp-content/uploads/2019/04/Venezuela.jpg

How to go from 2.4 million barrels per day to 700,000 bpd in just three years.

MarkW
Reply to  Javier
April 10, 2019 11:29 am

In your mind, the incompetence of those running the oil company has nothing to do with the drop off in production?

Javier
Reply to  MarkW
April 10, 2019 11:50 am

Seneca did not specify a required cause in his letter to Lucilius. He just said that the road to ruin is much faster. When things start to go wrong problems mount an a Seneca cliff often results. There is nothing mysterious about it, and ruling out the cause for one Seneca cliff does not mean that another cannot take place from different causes.

MarkW
Reply to  Javier
April 10, 2019 12:49 pm

Let me see if I have this right. Any sudden drop, regardless of cause, is a Seneca Cliff.
Really?

To be a Seneca Cliff, recovery is not possible as the resource is exhausted.
A production drop because of the incompetence of the operators can be reversed by bringing in competent operators. Therefor such a drop cannot be a Seneca Cliff.

Javier
Reply to  MarkW
April 10, 2019 1:38 pm

No, you don’t have it right. Seneca’s example was the fire that destroyed Lyon the previous summer. Lyon was reconstructed. The lesson is that what takes a lot of effort to build can collapse in a moment.

Venezuela’s oil production is a perfect example of a Seneca cliff. Another typical example is North Atlantic cod captures that peaked in 1980 and collapsed afterwards. The resource is not exhausted as cods are renewable but it might take a long time to increase their population to previous levels.

MarkW
Reply to  MarkW
April 10, 2019 3:53 pm

You just repeated the nonsense from earlier, using different words.
Every sharp drop off is proof of Seneca. No matter what happens, it’s proof that the theory is right.

Javier
Reply to  MarkW
April 11, 2019 2:18 am

You just repeated the nonsense from earlier, using different words.
Every sharp drop off is proof of Seneca. No matter what happens, it’s proof that the theory is right.

You just have the wrong idea about what a Seneca cliff is, and I am trying to explain politely.

The Seneca cliff is not a theory. It is an observation. As such it cannot be right or wrong, as observations simply are. It is the observation that many things that take a long time to became, collapse in a much faster way.

Whether post-Peak Oil production would suffer a Seneca cliff is anybody’s guess, but it is certainly a possibility. If the economy suffers badly from post-Peak Oil consequences oil might become unaffordable to most, and demand could crater.

Mexican Cantarell oil field also shows a Seneca cliff in oil production.

http://www.energycrisis.com/mx/images/cantarell.png

Seneca’s observation is valid 2000 years later because these sort of things happen.

MarkW
Reply to  MarkW
April 11, 2019 6:31 am

Every sudden drop is a Seneca cliff.
Got it.

R Shearer
Reply to  Javier
April 10, 2019 12:11 pm

Could you post this as an image? Links are just not convincing.

John Endicott
Reply to  R Shearer
April 10, 2019 12:28 pm

Javier’s link is to a jpg, so it is an image – just one you have to click on the link to see. Unfortunately only those with special permissions can post a link to an image and have it show up as an image.

Javier
Reply to  David Middleton
April 11, 2019 2:08 am

Rystad has it wrong. It is 2019 and Venezuela’s oil production is already lower than their low case. Predictions about oil production or oil price aren’t worth much. Venezuela’s decline is not due to sanctions. The decline in Venezuela’s oil production won’t be short term, since due to neglect a lot of the infrastructure is damaged and replacing it will take time and money.

Brett Keane
Reply to  David Middleton
April 12, 2019 1:16 am

And Cod never vanished, they just followed the AMOC line of their favoured ocean temperatures and food supplies. For some few years, they have been returning to their more southern haunts…. True Seneca curves await as David intimated, the passage of millions of years. Milankovich time in Cods’ case. Brett

Glenn Morton
Reply to  Javier
April 10, 2019 2:10 pm

I think there are two misunderstandings here. First I don’t know anyone who suggested Seneca cliff applies to oilfield decline. Gail Tverberg does apply to societal collapse which will in turn impact our ability to produce the last part of the oil. Venezuela is a temporary example. Get rid of the socialist down there, there is still an group of outsiders willing to help Venezuela recover. But if global economy were to collapse due to the high price of oil, there are no outsiders to help out. Producing oil requires a huge number of specialists who must be supported by an agricultural system which turns petroleum into food via petroleum based fertilizer and fuel. When peak oil production occurs, the agricultural system will be at risk and that in turn will risk societal collapse from starving people trying to survive.

JERRY HENSON
April 10, 2019 11:16 am

Davin,
I may have missed it, but in peak energy, I have not seen natural gas
hydrates in the mix.

I know that you know the difference between natural gas and methane,
but many people use the terms interchangeably.

For the people who missed the delineation, natural gas is made up of
mostly methane, but varies by location, ethane, propane, butane, and
small percentages of other gases such as CO2.

Vast volumes of natural gas hydrates lie within the legal boundaries
of the US.

When the cheap supplies of natural gas on land diminish, hydrates
will be exploited. The Chinese are beginning to do so now.

The method of recovery is likely, in my opinion, to be simple,
but very dangerous.

Cat cracking can convert the gas to diesel, gasoline, etc.

References for suggested reading:
https://energy.mit.edu/wp-content/uploads/2011/06/MITEI-The-Future-of-Natural-Gas-Supplementary-Paper-2.4-Methane-Hydrates-and-the-Future-of-Natural-Gas.pdf

http://www.truebluenaturalgas.org/how-much-natural-gas-does-the-us-have/

JERRY HENSON
Reply to  David Middleton
April 10, 2019 12:01 pm
sycomputing
Reply to  David Middleton
April 11, 2019 6:42 am
Walter Sobchak
Reply to  David Middleton
April 10, 2019 12:09 pm

“there’s currently no economic way to produce them.”

3 Things will happen.

1 is that when the supply of other hydrocarbons falls below demand, prices will rise until it is economic to use other resources.

And 2, the technological problem is not in a zone forbidden by the laws of physical science and mathematics (faster than light, sunshine in the nighttime), therefore it will, when prices provide a sufficient incentive, be solved, without warning.

3. “Environmentalists” will be dead set against it.

John Endicott
Reply to  Walter Sobchak
April 10, 2019 12:36 pm

Spot on Walter. Particularly number 3

Walter Sobchak
Reply to  David Middleton
April 10, 2019 2:36 pm

Is the higher rate forbidden by a law of physics or mathematics?

ResourceGuy
April 10, 2019 11:20 am

At this rate they will start to bother to look for pre-salt oil in about 20 years.

Basic question here: Does the dominant producer with the largest reserves have any incentive A) to look continuously for more reserves or B) to pursue high cost investment in production in known resources such as heavy oil, shale oil, or gas fields?

ResourceGuy
Reply to  ResourceGuy
April 11, 2019 8:55 am
Javier
April 10, 2019 11:46 am
Rud Istvan
April 10, 2019 11:51 am

David, excellent.
The IEA published a WEO 2008 survey of all of the worlds significant oil fields—all supergiants and giants, many majors—794 in total accounting for about 2/3 IIRC) of world production at that time. They were primarily seeking two pieces of information: estimated total recovery, and decline rate. They found that the best oilfields (like Ghawar or Samotlar) have estimated ultimate total recovery (primary plus water flood plus tertiary) averaging about 65% just as you calculate. But the average ultimate recovery for all 794 was 35% (higher viscosity, less favorable porosity and permeability). The average decline rate for all was 5.1%. Shows how the best compares to the average.
Wrote it up in one ov several oil focused energy essays in ebook Blowing Smoke.

Izaak Walton
April 10, 2019 11:57 am

David,
Peak Oil is implicit in what you wrote about. i.e.
“A 2% decline rate would lead to Ghawar producing just over 100% of its proved reserves (1p) from 2018-2077 (50.7 billion bbl).”
Any decline rate in production implies “peak oil”. Unless there is an infinite
supply which seems unlikely on a finite planet oil reserves are finite and will
decline to zero at some point in the future. You would appear to be placing
peak oil a some point in the relatively near future. Possibly around 2040 like Mike Jonas suggested recently.

MarkW
Reply to  Izaak Walton
April 10, 2019 12:53 pm

Peak oil for one field, would not be evidence that peak oil for the earth is at hand, or even close at hand.

William Astley
Reply to  MarkW
April 10, 2019 4:16 pm

It is odd that everyone forgets about ‘conventional’ hydrocarbons.

The Saudi oil reservoir is small compared to the Canadian high viscosity ‘heavy’ oil reservoir.

It is interesting when a person tries to explain why there are super large deposits of hydrocarbons, on the surface of the planet.

The Canadian Athabasca heavy oil deposit contains 1.7 trillion barrels of oil which is more than the entire world’s estimated 1.5 trillion barrels estimate of ‘conventional’ oil.

The unconventional heavy oil all contains massive amounts of heavy metals. The amount of heavy metals in oil increases as the oil viscosity increases.

The Canadian heavy crude is solid at room temperature. It must be melted and then diluent added to enable it to be shipped. The metals in the Canadian heavy crude are so high that a special catalyst is required for oil refining.

https://en.wikipedia.org/wiki/Athabasca_oil_sands

The Athabasca sticky (high viscosity) oil sands deposit contain roughly 1.7 trillion barrels of heavy oil.

https://en.wikipedia.org/wiki/Oil_reserves

This compares to the total oil reserves of the top 17 countries of 1.5 trillion barrels of oil and Venezuela’s heavy oil deposit of 1.2 trillion barrels.

The Orinoco Belt consists of large deposits of extra heavy crude. Venezuela’s heavy oil deposits of about 1,200 billion barrels (1.9×1011 m3), found primarily in the Orinoco Petroleum Belt, are estimated to approximately equal the world’s reserves of lighter oil.[1]

The Athabasca oil sands (or tar sands) are large deposits of bitumen or extremely heavy crude oil, located in northeastern Alberta, Canada – roughly centred on the boomtown of Fort McMurray. These oil sands, hosted primarily in the McMurray Formation, consist of a mixture of crude bitumen (a semi-solid rock-like form of crude oil), silica sand, clay minerals, and water. The Athabasca deposit is the largest known reservoir of crude bitumen in the world and the largest of three major oil sands deposits in Alberta, along with the nearby Peace River and Cold Lake deposits (the latter stretching into Saskatchewan).[3]

Together, these oil sand deposits lie under 141,000 square kilometres (54,000 sq mi) of boreal forest and muskeg (peat bogs) and contain about 1.7 trillion barrels (270×109 m3) of bitumen in-place, comparable in magnitude to the world’s total proven reserves of conventional petroleum.

William Astley
Reply to  David Middleton
April 10, 2019 5:22 pm

The Canadian heavy oil is found primarily three very large deposits, not basins.

When a deposit of oil is very large it does not change from a deposit to a basin.

‘Basin’ the word, as used in the oil industry, is a region where the oil deposits are found.

The Canadian heavy oil is oil, just oil with less hydrogen and lots of heavy metals.

comment image

William Astley
Reply to  David Middleton
April 10, 2019 5:24 pm

I missed adding a quote from my link.

“This map shows the extent of the oil sands in Alberta, Canada. The three oil sand deposits are known as the Athabasca Oil Sands, the Cold Lake Oil Sands, and the Peace River Oil Sands/”

brent
Reply to  William Astley
April 10, 2019 8:09 pm

William,
You will find the official numbers for Alberta Bitumen on Page 7 at link below
1.8 Trillion Bbl Initial in Place Resources
315 Billion Bbl Ultimate Potential (Recoverable)
177 Billion Bbl Initial Established Reserves
164 Billion Bbl Remaining Established Reserves

ST98: 2018ALBERTA’S ENERGY RESERVES& SUPPLY/DEMAND OUTLOOK
https://www.aer.ca/documents/sts/ST98/ST98-2018_Executive_Summary.pdf
Page 7

Most metals get rejected with PetCoke when one feeds the Bitumen to a Coker

Steve Fitzpatrick
Reply to  David Middleton
April 11, 2019 5:17 am

The relative inelasticity of demand means rapid upward price movement for petroleum when there is a significant shortfall relative to demand. Substantial long term price increases (inflation adjusted) over historical prices seem to me a strong indicator of resource limitation; that strong signal seems lacking at present. Of course, any rapid price increase will, in both the long and short term, lead to greater economically recoverable petroleum resource. It is probably impossible to define the inventory of “recoverable” petroleum, since the answer depends on how much marginal petroleum production is valued in the market. My guess is that the potential price is very high.

Dennis Sandberg
April 10, 2019 12:13 pm

Has Saudi Aramco done any exploration drilling in the huge Rub Al Khali area between the south end of Ghawar and the “new” Shayba field?

Steven Kopits
April 10, 2019 12:53 pm

Saudi Arabia is pumping less today than it was 1979. It is probably fair to say that the Kingdom is near the top of its production capacity. While it may stay there for some time, it is unlikely to cover much growth in demand.

Indeed, since 2005, US shales have provided 65% of oil supply growth by themselves, 77% with Canada’s oil sands. That is a remarkable degree of dependence on really a single source of supply — US shales. When shales falter, we’ll be right back in a high oil price environment.

David L. Hagen
Reply to  David Middleton
April 10, 2019 5:45 pm

For details see the excellent graphs of 2005-2019 by Ron Patterson at PeakOilBarrel.com eg
“OPEC March Data and Saudi Report” April 10, 2019
http://peakoilbarrel.com/opec-march-data-and-saudi-report/#more-21710
Note Patterson’s very detailed discussion of Saudi reserves and depletion rates.

Editor
April 10, 2019 12:53 pm

Thanks, David, extremely informative, clear, well written, well referenced.

The part I liked most was the part that “formed in response to right-lateral transpression”. I keep looking to see where that combination of words goes off my mental rails and I can’t find the exact spot. English is a wonderful language.

Much appreciated,

w.

NavarreAggie
April 10, 2019 1:14 pm

Quick clarification. I presume the following:

“The field averaged 820 bbl/d in 2018” in reference to the Eugene Island 330 field meant 820,000 bbl/d based on the y-axis on the plot above the caption.

Did I interpret that correctly? Surely, we would not be discussing 820 bbl/day.

April 10, 2019 2:24 pm

Conclusion: Ghawar is running out of oil, and we are very unlikely to ever find anything close to what that field has left today.

Did you ever wonder what all those Saudis are going to do when their population is 50 million and their oil production drops below 4 million BOPD? I think they will be heading north.

Patvann
Reply to  David Middleton
April 11, 2019 3:28 pm

Cool! I’m going to go ahead and put a blower on the Camaro. 😉

Thank you for another informative post.

John W. Garrett
April 10, 2019 3:07 pm

★★★★★

Thank you!!

sycomputing
April 10, 2019 3:35 pm

Dave:

Minor quibbles to an informative read (where IS Marcus????):

Corrections(?) bolded:

” . . . that the prospectus doesn’t really tell us much about(?) Ghawar’s decline rate.”

” . . . The presence of a positive paleo-structure, episodic reactivation of uplift and buried fault system provided for a high-energy depostional environment . . . ”

“Aramco plans on being able to produce 12 million bbl/d as for more than 50 years and they have the capacity to do so.”

David L. Hagen
April 10, 2019 5:30 pm

David Middleton – Thanks for your details and calculations.
Please expand on your the basis for recovery, especially
“Secondary Waterflood EOR 50%” vs “Tertiary CO2 injection EOR 60%”.
“OOIP 182,773,625,918 bbl
Primary Water Drive 40% 73,109,450,367 bbl
Secondary Waterflood EOR 50% 91,386,812,959 bbl
Tertiary CO2 injection EOR 60% 109,664,175,551 bbl”
i.e., how do you get more oil out than the Oil Originally In Place (OOIP).
1) What are the assumptions for Original Oil In Place OOIP?
2) How does Secondary Waterflood achieve 90% recovery of OOIP?
3) What are the assumptions for Tertiary CO2 EOR 60%? e.g.,
Is this Residual Oil Zones (ROZ) recovering oil below the conventional OOIP?
And/Or in separate along side recovery zones?
Has any of such tertiary CO2 EOR evidence been published for KSA?
E.g., see: Godec, M., Carpenter, S. and Coddington, K., 2017. Evaluation of technology and policy issues associated with the storage of carbon dioxide via enhanced oil recovery in determining the potential for carbon negative oil. Energy Procedia, 114, pp.6563-6578. https://www.sciencedirect.com/science/article/pii/S1876610217319975
PS Do any of those include the 500 ft thick “tar matt” layer mentioned by Matt Simmons in Twilight in the Desert p 174.
(I consider each of the CO2-EOR below conventional OOIP, separate EOR fairways, and this 500 ft thick tar mat, to be a different hydrocarbon resources from the OOIP, each of which could be modeled under a “Multi-Hubbert” analysis. e.g., see:
Höök, M., Tang, X. (2013) “Depletion of fossil fuels and anthropogenic climate change: a review” Energy Policy, 52: 797-809 URL: http://dx.doi.org/10.1016/j.enpol.2012.10.046
http://www.diva-portal.org/smash/get/diva2:561259/FULLTEXT06 )

Bruce of Newcastle
April 10, 2019 6:16 pm

About 183 billion barrels of oil.

To give a comparison, the North Sea coal seams contain up to 23 trillion tonnes of coal. Coal is oil that just hasn’t transitioned yet.

One tonne of coal produces about 2.5 bbl of crude, so the North Sea contains up to 57 trillion bbl of what is effectively crude oil, once you put it through a CTL plant. Ghawar is a drop in a bucket by comparison.

Crude from CTL is already pretty competitive, with a number of CTL plants in operation around the world today.

Anyone still talking about Peak Oil?

Dennis Sandberg
Reply to  Bruce of Newcastle
April 10, 2019 9:03 pm

Newcastle
Now I fully appreciate the saying, “that’s like carrying coal to Newcastle”. I had no idea of the quantity of coal. Amazing. Hope I can find something online about the geology.

John
April 10, 2019 7:16 pm

Abiotic is very reasonable to consider. Just look at Titan!

MarkW
Reply to  David Middleton
April 11, 2019 6:36 am

Beyond that, methane in the atmosphere doesn’t mean that there are also huge amounts of methane in the crust.

MarkW
Reply to  John
April 11, 2019 6:35 am

If oxygen producing plants had evolved on Titan, there wouldn’t be any methane left in it’s atmosphere either.

knaal
April 10, 2019 8:31 pm

I read about the immanent and drastic production decline of the Ghawar field back in 2005 or 2006, back when the US was producing about 5 or 6 million barrels per day ( and going down). Well, if I remember correctly, that didn’t happen 🙂

Mark Whelan
April 10, 2019 8:46 pm

Nice work David, thanks very much for your time in posting this.

Mark Whelan
Reply to  David Middleton
April 11, 2019 5:46 am

I did a couple of weeks consulting on the Hawiyah segment about 20 years ago. It’s a fascinating oil field to work on, incredibly complex at the pore scale and seemingly simple on the macro scale. Phenomenal geology in that part of the world.

Mark Whelan
Reply to  David Middleton
April 11, 2019 6:46 am

I think D&M definitely earned their stripes on that study 🙂

April 10, 2019 8:59 pm

David,

Excellent work. One of the best I’ve seen about Ghawar, and I’ve seen many!

Phil Sage
April 11, 2019 2:34 am

David
Fascinating stuff, My thin belief in the power of solar renewables further diminishes.

A genuine, slightly off topic question spawned by your brilliant diagrams. I “get” tectonic plate movement and volcanoes spewing materials from the core. I get the layering of biological materials on land and sea turning into rocks and fossil fuels over time. I get the water cycle and nutrients on the surface tending to be washed down.
But my dumb question is how did all that solid material get on top of what is already there? The earth crust is 30-45km deep and we have drilled down for oil 10km. That implies there is 10km worth of biologial material on top. How does it get there and where did it all come from? Basically just volcanic activity?

Phil Sage
Reply to  David Middleton
April 11, 2019 9:12 am

David
Sincere thanks for the prompt reply and the new graph which prompts an extra question.
I was thinking in terms of the volume of basic molecules forcing the original biological materials 10km undergound through sedimentation. Over the last 200m years essentially the top third layer of the crust has been replaced with molecules that came from somewhere. Tectonic movements and surface activity spawning erosion I get but once that organic layer has settled into sediment where does the new organic matter get its molecules from? Nitrogen fixing and co2 from the atmosphere is what grows plants but where do those molecules come from?

Extra question-Given that temperatures and CO2 was higher in the Jurassic period when most oil source rock was formed, are we in effect refertilising the atmosphere by using fossil fuels? There is 11% more greenery on the earth over the last 40 years after all.

Jeff Alberts
April 11, 2019 6:34 am

Silly question. Why do they say “proved” instead of “proven”?

JERRY HENSON
April 11, 2019 9:11 am

David,

Part of my argument for abiotic hydrocarbons is the Horsehead Nebular.

How does the fossil theory explain this phenomena?

http://annesastronomynews.com/the-horsehead-nebula-is-a-cosmic-petroleum-refinery/

JERRY HENSON
Reply to  David Middleton
April 12, 2019 4:23 am

David,

You think that botany, biology, chemistry, physics, and history
are different on earth than elsewhere in the universe? I
do not.

The atmosphere of every exoplanet that I have seen analyzed shows
hydrocarbons.

JERRY HENSON
April 12, 2019 5:22 am

The Horsehead Nebulae is said to be a star incubator. “Dust” clouds
accrete, start to swirl, form stars, and if it is not a binary, the residue
then starts to form planets, some possibly proto earths.

Actually, the numbers are soo large that there are probably nearly
exact copies of earth are out there. The hydrocarbons of the dust clouds
are included in all planets, then physics and chemistry take over.

Methane, ethene, and acetylene are detected in Saturn’s atmosphere.

As gravity concentrates the ingredients, physics and chemistry take over,
and larger molecules are formed.

Earths original atmosphere is thought to include methane and carbon
oxides. Hydrocarbons were always here.

http://planetfacts.org/the-atmosphere-of-saturn/
https://www.bing.com/search?q=earth%27s+original+atmosphere+was+made+of&form=EDGEAR&qs=SC&cvid=45376093e3814d8f8f100448ef7f7af7&cc=US&setlang=en-US&elv=AQj93OAhDTi*HzTv1paQdnh5hUnG0l2BUXDSl3j7teLkzBXHBGG%21F%21kFJ7cYdZtAbbg05ecR8P98QFp6P1aHsXGhzjDFI4LWQ4414gQrs34J&PC=HCTS

http://planetfacts.org/the-atmosphere-of-saturn/

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