An Analysis of John Matthews' "The Origin of Oil - A Creationist Answer"

Copyright 2008 G.R. Morton  This can be freely distributed so long as no changes are made and no charges are made.

John D. Matthews has published an article entitled, "The Origin of Oil -A Creationist Answer" in Answers Research Journal 1 (2008): 145-168. This article is now online  here  Answers in Genesis is the copyright holder of this article. This review is within their guidelines.

In the article, Matthews says that oil is neither biogenic nor abiogenic, but was created by God and then via migration, the oil moved into sedimentary reservoirs during the flood.

There are a couple of prefatory remarks that must be made. First, if God simply created the oil and created the geology, then there is simply nothing left to explain. There is also nothing to argue about. I have always said that if YECs want a perfectly logically coherent view, just simply say that God did it all and then no one really argue with you. But equally, there is no need for a YEC to then claim how bad modern science is or how wrong it is. It seems that Matthews' paper could have been significantly shorter simply by saying God made all the oil miraculously and emplaced it miraculously during the miraculous flood, which miraculously arranged all the sediments with their miraculous fossils and miraculous footprints, none of which signify previous plants, animals or activities. It is, a thesis that has been tried before, called Omphalos by Phillip Gosse. Edmund Gosse, his son wrote of this attempt, where everything was done miraculously. Phillip it seems expected adoration for solving the problem between geology and the Bible with his suggestion.  Unfortunately that wasn't to be the case.
"In the course of that dismal winter, as the post began to bring in private letters, few and chilly, and public reviews, many and scornful, my Father looked in vain for the approval of the churches, and in vain for the acquiescence of the scientific societies, and in vain for the gratitude of those 'thousands of thinking persons,' which he had rashly assured himself of receiving. As his reconciliation of Scripture statements and geological deductions was welcomed nowhere; as Darwin continued silent, and the youthful Huxley was scornful, and even Charles Kingsley, from whom my Father had expected the most instant appreciation, wrote that he could not 'give up the painful and slow conclusion of five and twenty years' study of geology, and believe that God has written on the rocks one enormous and superfluous lie,' - as all this happened or failed to happen, a gloom, cold and dismal, descended upon our morning teacups. It was what the poets mean by an 'inspissated' gloom; it thickened day by day, as hope and self-confidence evaporated in thin clouds of disappointment. My Father was not prepared for such a fate. He had been the spoiled darling of the public, the constant favourite of the press, and now, like the dark angels of old, so huge a rout Encumbered him with ruin.
�He could not recover from amazement at having offended everybody by an enterprise which had been undertaken in the cause of universal reconciliation.� Edmund Gosse, Father and Son, (New York: W. W. Norton, 1963), p. 88
The second prefatory remark concerns my qualifications to comment. I have worked in the oil industry for about 39 years, most of that time I was a geophysicist. I have done programming, was for a while a manager of marketing, a personnel recruiter and a log librarian. I have also been manager of reservoir modeling, manager of petrophysics, manager of geophysics for the Gulf of Mexico for 10 years, Manager of Geophysics for the North Sea (where Matthews has spent his career) for 3 years, a director of technology, and an exploration director(the top dog in the exploration of China for Kerr-McGee) with geologists and geophysicists and landmen reporting to me. I put this out so that no one will claim that I would be unknowledgeable in the areas of geology, geophysics, or engineering, all of which are addressed in Matthews' article

The first thing that attracted my attention was the silly claim that the oil industry doesn't use normal units. He claims that we use 5000 feet for a mile, 3 for the conversion of meters to feet, and one barrel equals 6 cubic feet. I have worked all over the world in the oil industry and lived on 3 continents, including the UK where Matthews is from. I have never seen anyone use non-standard systems of units unless they were wanting a mere estimate, a first order guesstimate, kind of like the mathematician Hardy did for the following equation.

"Hardy analyzed it, he demonstrated what was clearly an intuitive grasp of the nuances of numbers, powers, and margins of error. Surprisingly often in mathematics, the art is in knowing when and how to abandon the search for extreme accuracy a make approximations that allow the answer to come with much I effort. The problem, posed in Hardy's Collected Papers, is this:
Find an approximation to the large positive root of the equation
e(e^x) = 10l0xl0el0^(l0x^l0)

"In other words, what number substituted for x will make the left side equal the right?"
"Hardy describes the method of solving this problem. 'The points to observe are (i) that the factor 10[sup]10x^10[/sup] proves to be of no importance whatsoever, and (ii) that it is futile to try to be very accurate in the early stages of the work .... The great weakness of boys confronted with a numerical problem is that they cannot see where accuracy is essential and where it is entirely useless.' By the way the answer to the problem is that x is somewhere between 63 a 67, and, says Hardy, "a closer approximation could be found with little trouble."  G. H. Hardy, cited by Karl Sabbagh, The Riemann Hypothesis, (New York: Farrar, Straus and Giroux, 2002), p. 83
Matthews asserts
 "There are also the thorny issues of mercury, vanadium and chromium within oils" Matthews 2008
This is not thorny. Geochemists know of the issue
 "The Chlorophyll molecule loses its magnesium at the time of deposition. During diagenesis, both vanadium and nickel become complexed to the porphyrin in the place of the magnesium. As the porphyrins are introduced into a crude oil from the source rock, they carry the vanadium/nickel distribution with them. Many other trace elements in crude oils are simply a reflection of those picked up during migration or in the reservoir; so they have a limited value in correlation." John M. Hunt, Petroleum Geochemistry and Geology, 2nd edition (New York: Freeman and Co., 1996, p. 529
Matthews then acts as if overpressure were some problem for us in the industry.
 "In some reservoirs, compaction of the rock grains has not been fully achieved, even though such reservoirs are many miles below the surface. This means that the rock grains are not fully supporting the formations above. Part of that support comes from enhanced fluid pressures." 
"Wilson (2005) has pointed out the oil must have entered many types of reservoirs while the reservoirs were at a shallow depth, at which point there is only partial compaction. This causes him a problem, since the oil must leave the source rock early in its supposed process of catagenesis (see later)." Matthews 2008
Oil entering rocks which are at a shallow depth are due to mature source rocks much much deeper forming the oil and the oil and gas leaking up faults to the shallow surface beds. His comment fails to distinguish between the source bed, which is not young and the reservoir bed, which is young at the time of migration.
Matthews shows some lack of knowledge of the South Brae field.
If we adopt the model that oil is generated in the source rocks, then because the Kimmeridge Clay is the source rock for the South Brae field, then the Clay is both source and cap rock. That, of course, begs the question as to how the oil was ejected downwards against gravity, when we would expect it to be easier to move the oil upwards into the next formation. Matthews 2008
First off, he misrepresents the relation of the Brae reservoir to the source rock. It is interbedded in the source rock, which is why the oil is there.
"The Brae oil fields are at the southern limit of the Viking Graben, at its western faulted edge. Their Upper Jurassic reservoir sandstones are intimately interbedded with the KCF source rock, and form an aquifer beneath it." R. S. Haszeldine et al, "Diagenetic Porosity Creation in a Graben," in A. J. Fleet et al, eds, Petroleum Geology of Northwest Europe, Proceedings of the 5th Confernec, (London: Geological Society, 1999), p. 1347
What he doesn't tell people is that oil source rocks pressure up because the diagenetic change causes fluid to occupy more volume than the bitumen did. The change from bitumen to oil is a change like that of water to steam. The end product occupies more volume and creates high pressure. Now, this pressure is what causes oil to migrate downward. If the bed beneath the source rock is lower pressure than the source rock, flow will follow the laws of physics and it will go down. In point of fact most oil source rocks expel oil in both directions, up and down.
Lowest pressure
 -------top of source rock
High Pressure
-------base of source rock
low pressure but not as low as the lowest pressure at the top of the source rock

I would also note that the claim by YECs, in particular, Matthews that high pressures in the subsurface mean a young earth ignore the fact that compaction of the rock continues all the way down. As water leaks from an over pressured compartment, the sedimentary grains compact further and maintain the pressure. This compaction can be seen by the general fact that there is less and less porosity in the rock as one drills deeper. Matthews should know this and tell it to his readers. He goes utterly ignorant on fluid flow through the subsurface in the next quote
 "There is also quite a variation between the formation waters of reservoirs of similar age. In terms of uniformitarian timescales, this is a contradiction that the sedimentation took place in seawater that had had plenty of time to approach near equilibrium."  Matthews 2008
The above statement could only be true if there was no meteoric waters flowing through the rock (that is rainwater which hits the ground onshore and then pushes its way into the subsurface, freshening the salinity of some areas. Areas that are isolated don't get freshened. That is why there is a variation of salinity. No geologist worth his salt would claim that there is no water flow through the subsurface. It is a quite well documented occurrence. See this for a primer I would also note that a well drilled about 200 miles off Florida at the Blake Nose, in about 600 feet of water found a cave with brackish water flowing towards the Atlantic. That water was largely from rainfall that landed on Florida and then flowed out under the Atlantic continental shelf to the edge of the continent.
Matthews then claims that far more organic material is required to source oil than most experts believe.

 "The organic content of ocean sediments, such as in the North Atlantic, is around 0.1% by weight (Hunt 1979). Most other places are less than 1%, except for anaerobic areas such as the Black Sea with values of 6 to 15%. It is only with these last values that, even in the most unprescriptive conditions that have been suggested as part of this biogenic model, enough organic carbon can be found to make useful amounts of an oil-like substance. Mattews 2008

This is simply false
"Low energy coastal areas and inland sedimentary basins where fine-grained clay and carbonate muds are deposited generally contain 0.5 to 5% TOC, which is in the range of most oil-forming rocks." John M. Hunt, Petroleum Geochemistry and Geology, 2nd edition (New York: Freeman and Co., 1996, p. 326
Because of this, most authorities don't think it requires 10% carbon to make a source rock. 2% will often work just fine He fails to tell his readers that the Kimmeridge is highly organic. Total organic carbon is the way these numbers are often reported (TOC). He also doesn't tell his readers how little rock is required to produce a barrel of oil
 "A 5% organic carbon content, for example, corresponds approximately to an oil yield of 25 liters per metric ton of rock. Assuming a rock specific gravity of 2.3, a cubic metre of this source rock would yield approximately 57 litres of artificial oil. some 2.8 or roughly 3 cu. m. would be required to produce 1 bbl of oil." Hans R. Grunau, "Abundance of Source Rocks for Oil and Gas Worldwide," Journal of Petroleum Geology , 6:1, (1983), p. 42.
To put the above in perspective it would require the size of an average American bedroom of source rock to make a barrel of oil!
"The average TOC content of the Kimmeridge Clay is 5.6 percent wt at 2,600 to 3,200 m at pre-peak generation maturity. The average TOC content at the onset of oil generation (2550 m) was thus probably about 6 percent wt, which is equivalent to an organic matter content of 7 percent wt."J. C. Goff, "Hydrocarbon generation and Migration from Jurassic Source Rocks in the East Shetland Basin and Viking Graben of the Northern North Sea," Petroleum Geochemistry and Basin Evaluation, AAPG Memoir 35, ed. by Gerard Demaison and Roelof J. Murris, pp273-301, p. 290 [/cite]
He also fails to tell his readers that retorting experiments produce oil at source rock pressures and temperatures.
 "1) The Oxfordian source-rock interval has good to excellent source-rock potential (richness) with total-organic-carbon content (TOC) that ranges from 0.5 to 5 wt.% (average 1.7 wt.%) and S2 values from Rock Eval that range from 2 to 19 mg hydrocarbons (HC)/g rock (average 8 mg HC/g rock.) 
"2) The Kimmeridgian source-rock interval has fair to good source-rock potential with TOC ranging from 0.5 to 2 wt.% (average about 0.8 wt.%) and S2 values ranging from 2 to 6 mg HC/g rock (average 3 mg HC/g rock). 
"3) The Tithonian source-rock interval has very good to excellent source-rock potential, with TOC ranging from 0.5 to 16 wt.% (average 3 wt.%) and S2 ranging from 2 to 85 mg HC/g rock (average about 14 mg HC/g rock)." Leslie B. Magoon, Travis L. Hudson, and Harry E. Cook, "Pinienta-Tamabra(!)"A Giant Supercharged Petroleum System in the Southern Gulf of Mexico, Onshore and Offshore Mexico," in C. Bartolini, R. T. Buffler and A. Caritu-Chapa, eds., The Western Gulf of Mexico Basin: Tectonics, Sedimentary Basins, and Petroleum Systems, AAPG Memoir 75, (Tulsa: AAPG, 2001), p. 112
Here are some source rock organic carbon values (total organic carbon --TOC)
The Bazhenov Fm. has 10% TOC  It is the source rock for all of West Siberia. The  Domanik Formation has 20% TOC and is the source for the Volga Ural and Caspian area. G. F. Ulmishek and H. D. Klemme, Depositional Controls , distribution and Effectiveness of World's Petroleum Source Rocks, U.S.G.S. Bulletin 1931, (Washington: U. S. Gov't Printing Office, 1990), p. 15, 19
" However, the total organic carbon values in the Kimmeridge Clay can be exceptionally high in the case of the millimetre-laminated 'Blackstone Band' rising above 50%. This unique horizon was used as long ago as the Bronze Age for the manufacture of decorative bracelets, perhaps because of its attractive colour, unusually low density and ease of working." S. P. Hesselbo, "Late Triassic and Jurassic: disintegrating Pangaea," in Nigel Woodcock and Rob Strachan, editors, Geological History of Britain and Ireland, (London: Blackwell Science, 2000), p. 334
[grm-Below, This is the Shahejie formation which extends out to the Bohai Bay where I worked. Some areas out there had 10% TOC
"Source beds in the Huanghua Basin contain total organic carbon of 1.5-5.0%, chloroform soluble bitumen of 0.15-0.30%, total hydrocarbon content of 1500 to 2500 ppm, hydrocarbon yield of 20 x 106tonne/km3 and potential hydrocarbon production of 10 to 30 kilograms/tonne of rock. KEQIN TIAN, YANMIN SHI, RUOZHE QIN, N.J. MCMILLAN AND EJ. LEE, "Petroleum geology of the Huanghua Basin," eastern China I,BULLETIN OF CANADIAN PETROLEUM GEOLOGY, VOL. 44, NO. 4 (DECEMBER 1996), P. 595-614, p. 595
From notes I took while I was in China, the Enping and WenJiang formations of South China have organic contents of 2%
When he quotes Waples as saying that Basin modeling hasn't delivered on its promises, Matthews hides from his readers that a major problem with basin modeling and migration modeling is that one must get the correct thermal history. I was involved in modelling a small basin in the Bohai. We were using a modeler in the US who was using US values for thermal history, source rock quality etc. Since I could read a wee bit of Chinese, I dug into the ChHinese literature looking for what the local knowledge had to say. What they said was that the TOCs were higher, the thermal history hotter, and pulsated rather than the simple cooling model that that US person was using. I pointed these values out to the US based modeler, who ignored me and told me I didn't know what I was talking about. She also concluded that there could be no oil in that basin.
The problem was that there was already a 50 million bbl oil field in that small basin about 10 miles south of where I wanted to drill. In order to get the well drilled I had to convince management that the modeling work was crap, which is was. We did a drill stem test on the well we eventually drilled of 1100 bbl/day. It was the first successful exploration well in China for our company in 5 years. Sometimes the modeling failure is one of not being optimistic enough.

Matthews then says
" The alkane distribution is completely different to that of oil in the reservoir. No alkanes lower than number 15 are generated. No even numbered alkanes are generated. The sheer disparity between what is found in reservoirs and what we have produced is shown in Fig. 7." Matthews 2008
With time, heat breaks longer chains to shorter chains. This isn't so hard to understand. Also one must not forget that there are lots of bacteria in the deep biosphere which munch on hydrocarbons and change the pattern.
He also says that if oil migrates in solution with natural gas, that we shouldn't find oil without gas. We almost never do. Almost all oil fields have some gas with them. Some have more than others. Often the gas and oil are mixed together where there is no gas cap. This happens when the pressure on the reservoir is sufficient to drive the two materials into solution with each other. And sometimes when we produce a field, we drop the reservoir pressure and gas comes out of solution forming a gas cap that didn't exist before we produced the field.
One other thing that Matthews doesn't tell his readers. A trap for an oil field is a relative term. A bed or fault that will trap asphalt, might not trap oil. A trap that traps oil and asphalt might not trap gas. Consider how leakey traps are to natural gas.
"For example, existing gas accumulations can be destroyed by dissipation. The rate of this destruction was calculated for the Harlingen gas field, Holland. By diffusive loss through 400 m of shale cap rock, the initial amount of methane in place of 1.93 x 10^9 std m^3 (6.8 x 10^10 scf) is reduced by one half over a period of 4.5 million years. this leads us to propose the concept that large gas accumulations can persist through extended periods of geologic time only as dynamic systems reaching some kind of steady-state equilibrium between diffusive loss through the cap rock and continuous replenishment from the source rock." Detlev Leythauser et al, "Role of Diffusion in Primary Migration of Hydrocarbons," AAPG Bulletin, April, 1982, p. 408
 This tells me that if oil does migrate in solution with gas, the gas might leak away over time faster than the oil does, thus causing an oil field lacking lots of gas. Of course, Matthews doesn't bother to tell his readers of this possibility.
 " In a desired model of secondary migration, faults appear to be conduits for migration at some times and barriers at others (Barker 1996, p. 384). There is no logic to this, other than to get the petroleum into the reservoir by a secondary migration model, and then keep it there." Matthews 2008
In the Bohai Bbay there are earthquakes all the time. This means that throughout geologic time, a fault may be pushed closed and then opened when the stress field changes. This turns a closed fault into an open fault. There is logic to it but it isn't predictable. The stress field of an area will change, sometimes opening the faults so migration happens, and sometimes closing it.
When he complains that there is bitumen above the gas fields of West Africa, and says we shouldn't find bitumen there, I am gob-smacked by the silly claim. Bitumen can be found anywhere it is deposited. There is also another mechanism. Bacteria eat the lighter carbon chains. This happens in the North Sea. It is called biodegredation and is well known, and should be well known by a guy with experience in the oil industry. There are lots of fields in the North Sea which have very heavy oil and are close to the surface.
Some miscellania. When he discusses the sourcing of oil into Wytch Farms, a field Kerr-McGee was a minority owner in, he shows one cross section, a north south cross section. What he doesn't show is what is happening in the east-west direction. The faults in the field run east west but are open to the east and west This link takes you to a 3d image of Wytch Farms. South is coming out at you at 45 deg to the right. You can orient yourself by the coast at the top of the picture as Wytch Farms is on the southern part of the English Coast. The big blue drop off in the front, is the fault that he says oil can't cross. Fine, but look at the drop off to the Northeast. Oil can get from source rock to older reservoir beds across that boundary. When Matthews claims that because Gullfaks is a big field there therefore MUST be smaller accumulations around it, that is utter nonsense. There simply is no criteria that there must be smaller accumulations around a large field. Often there are, but it is not a geologic requirement of the data.
Below is another ridiculous claim
 "The failure of drilling to find the conduits by which oil entered Sm�rbukk meant that the engineers had to use indirect methods to try and understand how oil entered Sm�rbukk."
No one drills to find the conduit to an oil field. NO ONE. Wells are too expensive to be mere science fair experiments. The engineer doesn't care how the oil entered the reservoir. The geologists cares only to the point that one wants to find other fields along the migration path, but there is no requirement that there be other fields along the migration path. Sometimes there are; sometimes there aren't.
My deep suspicion is that John Matthews is a much better geologist at work than he shows himself to be in this article.
I would also comment that his time spent describing various oil and gas fields seems wildly out of place in the article. The structure of a field has little to do with the origin of oil but might have something to do with the migration of oil, something that he believes happened. He doesn't seem to deny migration. Thus if a field has a problem getting oil into it under the biogenic theory, it would also have that problem under the flood theory.
One interesting thing is that Matthews starts his article by implying that the Western oil industry rejected the inorganic origin of oil theory in 1969. This is totally false. I know of only one or two people who hold to abiogenesis. The vast majority hold to the biogenic origin of oil.

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