Oil, Gas, and the Flood

Didyk, Borys M., and Bernd R. T. Simoneit.  “Hydrothermal oil of Guaymas Basin and implications for petroleum formation mechanisms.”  Nature 342(6245):65–69.  Nov 2, 1989.  A research paper on oil from a hydrothermal vent in the Guaymas Basin.  The authors found the oil similar to conventionally exploited crude oils, dated it by carbon-14 to under 5,000 years old, and estimated how much oil the hydrothermal area could have made.  The article uses it for the oil's young age, and for the small quantity that the authors' own estimate allows.

1. 1a.

   Table 2, page 68:  “In Guaymas Basin the presently known area where hydrothermal activity reaches the sea floor is ~3 x 10 km² and the lower 120-m section of the sediments drilled was hydrothermally altered.  An average porosity of ~50% and an organic carbon decrease from 2.0 to 0.2% (typical of the area) give a value for total organic matter (oil potential) susceptible to hydrothermal alteration and fluid leaching of the order of 1.3 x 10⁶ t km⁻² of alteration zone.  This gives a maximum organic-matter availability of ~40 x 10⁶ t for the presently known hydrothermally active area of the basin.  So far no data is available on the ultimate efficiency of hydrothermal petroleum generation processes prevailing in Guaymas Basin.”  “The major part of the oil plume above the vent area dissipates into the water column mainly by dispersion, dissolution and eventual biodegradation.”  The authors also write that "high efficiency and significant quantities of hydrothermal oil could have been generated" by the known 30 km² over its active lifetime, and that yields from larger hydrothermal areas "could be considerably greater." ↩

2. 1b.

   Section Abstract, page 65:  “Here we report the evaluation of such a hydrothermal oil, which we find to be similar to conventionally exploited crude oils.  Its young geological age (< 5,000 yr, ¹⁴C) indicates that a significant fraction of the organic carbon in the oil has completed the transformation from biomass to migrating oil in less than 5,000 years, thus limiting the oil generation, expulsion and migration processes to a geologically short timescale.” ↩ ↩

Tissot, B. P., and D. H. Welte.  Petroleum Formation and Occurrence.  Springer-Verlag, Berlin.  2nd edition.  1984.  A textbook on how petroleum forms and where it is found.  The article uses it for the temperatures at which source rocks start to make oil in real basins, and for how long that takes.

1. 2a.

   Page 517:  “b) 0.5 to 0.7% < Ro < ca. 1.3%:  catagenesis stage, main zone of oil generation;  also referred to as oil window.” ↩

2. 2b.

   Page 179:  “Bitumen and hydrocarbon ratios change little down to depths of ca. 1500 m in Paris and Douala basins, more than 3500 m in Uinta basin, 2400 m in the Los Angeles basin and still deeper in the Ventura basin.  According to local geothermal conditions, these depths correspond, respectively, to about 60°C (Paris Basin), 70°C (Douala basin), 100°C (Uinta basin) and 115°C (Los Angeles and Ventura basins).  Beyond that threshold, the transformation ratios increase rather abruptly.” ↩ ↩ ↩

3. 2c.

   Page 585:  “[at] the peak of oil generation the average activation energy is E = 40 to 60 kcal mol⁻¹, and in the gas zone it reaches E = 50 to 70 kcal mol⁻¹.  It should be remembered that an activation energy E = 50 kcal mol⁻¹ corresponds approximately to reaction rates multiplied by 5 every 10°C and E = 65 kcal mol⁻¹ to rates multiplied by 10.”  Page 584:  The book warns that the older Lopatin rule of doubling every 10 °C.  “is only valid for reactions with an activation energy in the range of E = 10 to 25 kcal mol⁻¹.” ↩

4. 2d.

   Page 223:  With Fig. II.7.4 on p. 222.  Page 225:  “the elapsed time from sedimentation until the rock enters the principal zone of oil formation may vary considerably from a few million years to more than 300 million years.” ↩ ↩ ↩

5. 2e.

   Page 592:  “Type-II kerogen contains slightly less of the labile organic material resulting in a genetic potential slightly lower than in type I.  However, the distribution of activation energies is wide and includes lower values than type I with a mode at 50 kcal mol⁻¹.” ↩

6. 2f.

   Page 653:  A table of oil-window timing by basin: Paleozoic E. Illizi enters the window 190 million years after deposition and leaves it at 300; Jurassic Paris Basin 100 to 170; Cretaceous Western Canada 25 to 37; Late Tertiary Los Angeles 12 to 18 and Pannonian 7 to 10.  Page 600:  In young rift basins with high heat flow.  “moderately buried source rocks may reach the principal zone of oil formation within 5 or 10 million years after deposition.” ↩

Batten, Don (ed.)  “Age of the earth: 101 evidences for a young age of the earth and the universe.”  Creation Ministries International.  2009.  Retrieved Sep 1, 2026.  A web page of 101 short arguments for a young age of the earth and the universe, published by Creation Ministries International in 2009 and later updated.  The article quotes its item on pressure in oil and gas wells word for word, and says that item has no permeability figure and no calculation.

1. 3a.

   Section Geological evidences:  “Pressure in oil / gas wells indicate the recent origin of the oil and gas.  If they were many millions of years old we would expect the pressures to equilibrate, even in low permeability rocks.  'Experts in petroleum prospecting note the impossibility of creating an effective model given long and slow oil generation over millions of years (Petukhov, 2004).  In their opinion, if models demand the standard multimillion-years geochronological scale, the best exploration strategy is to drill wells on a random grid.' —Lalomov, A.V., 2007.  Mineral deposits as an example of geological rates.  CRSQ 44 (1):64–66.” ↩ ↩

2. 3b.

   CMI's "Arguments we think creationists should NOT use" and AiG's "Arguments to avoid" pages do not mention oil, petroleum or reservoir pressure. ↩

3. 3c.

   “Direct evidence that oil is forming today in the Guaymas Basin and in Bass Strait is consistent with a young earth (although not necessary for a young earth).”  “Carbon-14 in oil again suggests ages of thousands, not millions, of years.” ↩

Lewan, Michael D., and Allison A. Henry.  “Gas:oil ratios for source rocks containing Type-I, -II, -IIS, and -III kerogens as determined by hydrous pyrolysis.”  USGS Open-File Report 99-327.  1999.  A U.S. Geological Survey report of hydrous-pyrolysis experiments on five immature source rocks, showing how the ratio of gas to oil changes with kerogen type and thermal maturity.  The article uses it for the standard protocol of 72 hours and for the low-rank coal that reached 1.55% vitrinite reflectance.

1. 4a.

   Page 2:  “All of the experiments considered in this study were conducted for 72 hours at temperatures ranging from 160 to 365°C (Table 2).  These experimental conditions simulate thermal maturities associated with oil generation.”  “Low-rank coals (< 0.5%Ro) subjected to hydrous pyrolysis at 355°C for 72 hours obtain random mean vitrinite reflectance values of 1.55 %Ro (Lewan, 1993b).”  Page 3:  No gas-oil ratios are calculated below 270 °C because no expelled oil is generated below that temperature in 72 hours. ↩ ↩ ↩

Saxby, J. D., and K. W. Riley.  “Petroleum generation by laboratory-scale pyrolysis over six years simulating conditions in a subsiding basin.”  Nature 308:177–179.  1984.  A laboratory experiment that heated potential source material from 100 to 400 °C over six years, rising 1 °C per week, to simulate the heating of rock buried in a steadily subsiding basin.  After four years it made a product indistinguishable from paraffinic crude oil from torbanite, and a brown coal gave products related to wet natural gas, with no olefins or carbon monoxide.  The article uses it as the slow case, which made crude only after four years of heating.

1. 5a.

   Section Abstract, page 177:  “we have heated potential source material from 100 to 400 °C over six years, increasing the temperature by 1 °C per week.  This was done in an attempt to simulate the thermal history of a sample being buried in a continuously subsiding basin with a constant geothermal gradient.  After four years, a product indistinguishable from a paraffinic crude oil was generated from a torbanite, while a brown coal gave a product distribution that could be related to a wet natural gas.  Of great significance is the absence of olefins and carbon monoxide in all products.”  At 1 °C per week from 100 °C, four years is about 308 °C. ↩ ↩ ↩

Peter, J. M. et al.  “¹⁴C ages of hydrothermal petroleum and carbonate in Guaymas Basin, Gulf of California: implications for oil generation, expulsion, and migration.”  Geology 19:253–256.  1991.  A 1991 radiocarbon study of hydrothermal petroleum and carbonate in the Guaymas Basin, Gulf of California, whose petroleum gave ages of 4240 to 5705 years B.P.  The authors say these are not true ages but the age of the carbon in the material, and Snelling 1990 reports "between 4,200 and 4,900 years, with uncertainties in the range 50–190 years" from a 1988 conference abstract by the same group.  The article uses the petroleum ages as its example of Guaymas oil that is only thousands of years old.

1. 6a.

   Section Abstract, page 253:  “The ages for petroleum range from 4240 to 5705 B.P., whereas those for calcite range from 7340 to 33,168 B.P.  The CO₂ in a sample of hydrothermal vent fluid (24% end member) yielded an apparent age of 14,820 B.P., which is within the calcite age range.  These are not true ages, but rather they reflect the age of carbon within these materials.  The data indicate that the conversion of sedimentary organic matter to petroleum occurs very rapidly and that the petroleum is mobilized from sedimentary organic matter in the upper 30 m of the sediment column (≤500 m thick) underlying the sea-floor deposits.” ↩ ↩ ↩

2. 6b.

   Table 1, page 254:  Petroleum: 4240 ± 185, 4875 ± 190, 5705 ± 300 yr B.P.  Calcite: 7340 ± 90 to 33,168 ± 340.  Vent fluid: 14,820 ± 100.  Page 255:  “The true ages may be as much as ~500-3000 yr younger than listed because reworked material may have been incorporated in the samples and because of the marine-reservoir effects”.  “Temperatures of up to 150-200 °C within 20-30 cm of the sea floor ... allow rapid petroleum generation at shallow depths”.  “these ages reflect the age of the carbon (derived from organic matter) present within the oils.”  Page 256:  “these are the youngest natural petroleums on Earth.” ↩ ↩

Simoneit, Bernd R. T. et al.  “Characterization of hydrothermally generated oil from the Uzon caldera, Kamchatka.”  Applied Geochemistry 24(2):303–309.  2009.  A chemical analysis of oil that collects in the Uzon caldera, a volcanic area in Kamchatka, Russia.  It dates the oil by carbon-14 at 1030 ± 40 years BP (measured) or 940 ± 40 years BP (conventional), and its carbon-13 value is consistent with a biological origin.  The article uses it for its example of oil in Kamchatka that is about a thousand years old.

1. 7a.

   Section Abstract, page 303:  “The ¹⁴C ages determined are 1030 ± 40 a BP (measured) or 940 ± 40 a BP (conventional).  The δ¹³C value is −30.6‰ versus the PDB standard, a value consistent with a biological origin.  The nearly contemporary age of the C content indicates a geologically recent origin from biogenic detritus and not by synthesis from mantle C.  The biogenic origin is supported by the presence of sterane and hopane biomarkers and the δ¹³C value of the bulk oil.  The overall compositions of the oils indicate that they are derived from rapid hydrothermal alteration of algal/bacterial mat detritus.” ↩ ↩

Snelling, Andrew A.  “How fast can oil form?”  Creation 12(2):30–34.  1990.  A 1990 article in Creation magazine by Andrew A. Snelling, written from a young-earth position.  It reviews the six-year CSIRO heating experiments and the Guaymas Basin hydrothermal oil, dated to 4,200 to 4,900 years, and argues that hydrothermal generation fits the time since Noah's Flood.  The article calls the Guaymas evidence in it the strongest the young-earth literature has on petroleum.

1. 8a.

   The article describes Saxby & Riley 1984 and Saxby et al. 1986 (Organic Geochemistry 9:69) and the Guaymas work accurately, and is the best-argued creationist treatment of rapid oil formation. ↩

2. 8b.

   “At less than 300°C, 35 percent of the oil shale had been converted to a paraffinic crude oil.  At 350°C not only was generation of the oil complete, but 'cracking' of the oil had occurred extensively.”  On the brown coal:  “Between 250°C and 300°C ... the brown coal produced about 1% short-chain hydrocarbons and 0.2% oil.” ↩

3. 8c.

   “Along these fractures through the sediments in the basin flows boiling hot water at temperatures above 200°C”.  “Samples have yielded ages between 4,200 and 4,900 years, with uncertainties in the range 50–190 years”.  “the temperature conditions in these hydrothermal fluids, of up to and exceeding 315 °C, are similar to the ideal temperatures for oil and gas generation in the previously described Australian laboratory experiments.” ↩

4. 8d.

   “this model for hydrothermal generation of petroleum is more than a feasible process for the generation of today's oil and gas deposits in the time-scale subsequent to Noah's Flood.” ↩ ↩

Computed for this article;  script at research/arrhenius.ts.  First-order Arrhenius kinetics, k = A·exp(−Ea/RT), isothermal conversion X = 1 − exp(−k·t), solved for T.  Inputs:  Ea = 50 kcal/mol (Tissot & Welte 1984, p. 592, the mode for type II;  p. 585, peak-oil average 40 to 60);  A = 10¹³ s⁻¹ (Waples & Yang 2023, p. 1, the EASY%Ro frequency factor);  R = 1.987 × 10⁻³ kcal mol⁻¹ K⁻¹.  Sensitivity:  Ea = 40 gives 134/150/161 °C for one year, 75/86/94 for 4,500 years and 34/43/49 for 10 Myr;  Ea = 60 gives 337/362/378, 249/266/278 and 187/201/210.  The full EASY%Ro table was obtained later and the calculation rerun;  see the next footnote.  A second check with the Lopatin-style rule Tissot & Welte give (rate × 5 per 10 °C at Ea ≈ 50):  compensating a time ratio of 10 Myr / 4,500 yr = 2,222 needs about 48 °C more heat, and about 111 °C under the older doubling rule. ↩ ↩ ↩

Computed for this article;  script at research/easyro-isothermal.ts (Deno).  Inputs are Sweeney & Burnham 1990, Table 1 (p. 1561):  twenty activation energies from 34 to 72 kcal/mol in steps of 2, with weights 0.03, 0.03, 0.04, 0.04, 0.05, 0.05, 0.06, 0.04, 0.04, 0.07, 0.06, 0.06, 0.06, 0.05, 0.05, 0.04, 0.03, 0.02, 0.02, 0.01 (sum 0.85), A = 10¹³ s⁻¹, and %Ro = exp(−1.6 + 3.7F) where F = Σ wᵢ(1 − exp(−A t exp(−Eᵢ/RT))).  The table was read from archive.org's microfilm scan of the AAPG Bulletin and cross-checked against two independent code implementations of EASY%Ro.  Converse values:  after 4,500 years isothermal, Ro = 0.36% at 100 °C, 0.62% at 150 °C, 1.04% at 200 °C;  after 10 Myr, 0.63%, 1.16% and 2.29%. ↩ ↩ ↩

Lewan, M. D.  “Evaluation of petroleum generation by hydrous pyrolysis experimentation.”  Philosophical Transactions of the Royal Society A 315(1531):123–134.  1985.  A paper by M. D. Lewan of Amoco Production Company's research centre on hydrous pyrolysis, a laboratory method that heats organic-rich rock in liquid water below 374 °C to make oil.  It says the method gives information on the stages, kinetics and indices of petroleum generation that the natural system alone makes hard to obtain.  The article uses it for the method's key result, that the expelled oil floats on the water and has no measurable olefins.

1. 11a.

   Section Abstract, page 123:  “This technique maintains a liquid water phase in contact with organic sedimentary rocks during their heating at subcritical water temperatures (less than 374 °C).  The expelled oil accumulates on the water surface and contains no measurable olefinic hydrocarbons.  Hydrous pyrolysis provides a means of acquiring information relating to stages, kinetics and indices of petroleum generation that would be difficult to obtain from a study of only the natural system.” ↩ ↩ ↩

Bruce, Richard.  “Millions of years are not necessary for petroleum formation.”  Journal of the Biblical Creation Trust (e-Origins) 3:7–11.  2021.  Page 10:  “presented in a private capacity only, and not as a representative of my secular employment with a Mines Department in Australia.”  A short review in a creationist journal arguing that temperature, not time, controls how fast petroleum forms, so oil can form in years to thousands of years.  It covers laboratory heating experiments and a kinetic model (a rate model of how fast a reaction runs at each temperature) by Nielsen and Barth.  The author has a secular job in an Australian mines department and says on p. 10 that the article is a private view, not a statement by that employer.  The article uses it as the one creationist paper that works through a published kinetic model, and it concedes that the thousand-year figure needs about 200 °C.

1. 12a.

   Page 8:  “Modelling by Middleton indicates that after 1000 years, peak bitumen generation can occur within temperatures realisable in sedimentary basins (about 200 °C or about three kilometres depth) (Bruce et al. 1996)”.  “hydrous pyrolysis indicates that significant volumes of petroleum may be generated at temperatures in the vicinity of 200 °C, if maintained for the order of 1000 years.”  Page 10:  “subsurface situations with temperatures of 200 °C – peak generation can occur in approximately one thousand years.  The bottom line is that economic accumulations of oil and gas can be generated in thousands of years in sedimentary basins that have experienced hot fluid flow for similar durations.” ↩ ↩

2. 12b.

   Pages 9–10:  “a model that is more realistic to natural systems is the hydrodynamic (moving fluids) model”.  The example is the Cooper-Eromanga case, in which.  “The depth-to-onset of oil generation is some 500 metres shallower than would be expected by just burial depth and conductive heat flow.” ↩

Snelling, Andrew A.  “The Origin of Oil.”  Answers 2(1):74–77.  2007.  A magazine article by Andrew A. Snelling of Answers in Genesis, arguing that oil and gas are of organic origin and formed recently, during the Flood.  It relies on porphyrin experiments and on a sidebar about turning animal wastes into oil, and it says that heat from Flood burial made the oil.  The article uses it because the same author argues from porphyrins for a biological origin, while giving the heating that the model needs with no temperature or time.

1. 13a.

   “Most scientists agree that hydrocarbons (oil and natural gas) are of organic origin.  A few, however, maintain that some natural gas could have formed deep within the earth, where heat melting the rocks may have generated it inorganically.  Nevertheless, the weight of evidence favors an organic origin.” ↩ ↩

2. 13b.

   “Experiments have produced a concentration of 0.5% porphyrin (of the type found in crude oils) from plant material in just one day, so it doesn't take millions of years to produce the small amounts of porphyrins found in crude oils.  Indeed, a crude oil porphyrin can be made from plant chlorophyll in less than 12 hours.”  The cited source is DiNello & Chang 1978, a chapter in The Porphyrins vol. 1 (Academic Press) on isolating and modifying natural porphyrins in the laboratory, not a burial simulation; its procedure is at p. 328, and the "12 hours" sentence carries no citation.  The "2–5 days" brown-coal claim rests on Brooks & Smith 1969 (GCA 33:1183), which ran at 210 to 330 °C in sealed tubes with water (quoted in Part 1); the sidebar's thermal-conversion plant runs.  “to 500°F (260°C) and pressurized to 600 pounds per square inch.” ↩

3. 13c.

   “other experiments have shown that plant porphyrin breaks down in as little as three days when exposed to temperatures of only 410°F (210°C) for only 12 hours.  Therefore, the petroleum source rocks and the crude oils generated from them can't have been deeply buried to such temperatures for millions of years.”  No source is cited for the 210 °C experiment. ↩ ↩

4. 13d.

   “The coal beds and fossiliferous sediment layers became deeply buried as the Flood progressed.  As a result, the temperatures in them increased sufficiently to rapidly generate crude oils and natural gas from the organic matter in them.” ↩

McQueen, David R.  “The chemistry of oil—explained by Flood geology.”  ICR Impact, Acts & Facts 15(5).  May 1, 1986.  A short popular article from the Institute for Creation Research that argues oil's chemistry shows it formed rapidly, during a worldwide Flood.  It reviews porphyrins, molecules found in both oil and plants, and quotes a laboratory procedure from a reference book.  The article says the porphyrin figures that later creationist writers repeat descend from this article, and Snelling 2009 cites it on p. 970, note 18.

1. 14a.

   “DiNello and Chang report the breakdown of a plant porphyrin in about three days under an experimental procedure which reached a temperature of 210 degrees C for about a 12-hour period.  As they conclude:  The yield of pure pyrrhoporphyrin is about .5 gm from 100 gm of crude chlorophyll extract.  In other words, they produced a .5% concentration of a type of porphyrin found in oil from plant material in one day.  A crude oil porphyrin can be made from chlorophyll (and presumably hemoglobin) in even less than 12 hours.  Fuhrhop and Smith found that 80% of the porphyrins in a sealed glass tube were broken down when heated to 165 degrees C for four hours in the presence of vanadium tetrachloride.”  McQueen's conclusion is that.  “porphyrins can be produced from chlorophyll in a matter of hours.” ↩ ↩

Whitcomb, John C., and Henry M. Morris.  The Genesis Flood: The Biblical Record and Its Scientific Implications.  Pages 429–437.  Presbyterian and Reformed (Philadelphia).  1961.  A 1961 creationist book by John C. Whitcomb and Henry M. Morris.  Its oil section, "Origin of Oil and Mineral Deposits", quotes Cox that no petroleum has been found to have formed since the Pliocene.  The article uses it to show that the overpressure argument is not in this book.

1. 15a.

   Page 432:  Quoting Cox:  “Petroleum occurs in rocks of all ages from the Cambrian to the Pliocene inclusive, but no evidence has been found to prove that any petroleum has been formed since the Pliocene”.  “We would suggest that there must be a connection between the fact that Pleistocene and Recent sediments are post-Diluvian and the fact that in these only has no petroleum deposit been found.  Otherwise the reason for this fact is quite mysterious.”  Page 434:  “The great sedimentary basins being filled rapidly and more or less continuously during the Flood would provide a prolific source of organic material, together with whatever heat and pressure might have been needed to initiate the chemical reactions necessary to begin the transformation into petroleum hydrocarbons.”  The word "pressure" occurs in the oil section only in that sense; the reservoir-overpressure argument is not in the book. ↩ ↩

Cook, Melvin A.  Prehistory and Earth Models.  Pages 254–262.  Max Parrish (London).  1966.  A 1966 book by Melvin Cook.  Its chapter XII, "Origin and Geology of Oil and Gas", argues in its sections "Deep Well Conditions" and "Sudden Burial Mechanism" that the pressures found in deep wells point to sudden deep burial.  The article traces the overpressure argument to this book.

1. 16a.

   Page 259:  “Further consolidation after complete sealing off of a formation above a given level would eventually (after a few thousand years at most) pressurize to the normal gradient the fluid uniformly below this level ... The concept of a reservoir above a source rock would require enough permeability to establish a normal gradient certainly in much less than a million years.  Therefore, this condition would appear to require sudden deep burial.” ↩

2. 16b.

   Page 260:  HR is Hubbert & Rubey 1959, GSA Bulletin 70:115–206.  “HR made order-of-magnitude calculations of the permeabilities of typical shales and concluded that extremely low permeabilities around 10⁻⁸ millidarcies would be required under the rates of loading corresponding to uniform sedimentation in these shales and the observed values of λ.  Cores of shales studied by Gondouin and Scala [1958] taken at depths up to 11,000 ft exhibited actual permeabilities in the range of 10⁻⁵ millidarcies and greater.  The observed permeabilities seem, therefore, to be hundreds to thousands of times greater than those required by a uniformitarianism model of deposition ... These facts are irreconcilable with a uniformitarianistic model, and even with a catastrophic one in which the sudden deep burial is assumed to have occurred millions of years ago.” ↩ ↩

3. 16c.

   Page 262:  “Certainly, sudden deep burial is the most likely explanation.  These interesting and crucial world-wide pressures and pressure gradients in deep wells probably, therefore, represent a serious blow to the doctrine of uniformitarianism.” ↩

4. 16d.

   Page 258:  Quoting Hubbert & Rubey:  “most abnormally high fluid pressures are in areas of very thick sections of relatively young sediments (Mid- and Late-Tertiary, and Pleistocene), and in or immediately below thick sequences of shale, salt, anhydrite, limestone, or dolomite.” ↩

Computed for this article from Neuzil's expression t ≈ 0.1 S_s l²/K for the onset of dissipation and t ≈ S_s l²/K for its completion.  Hydraulic diffusivity D = k/(μ S) with specific storage S ≈ 10⁻⁹ Pa⁻¹ and water viscosity μ = 10⁻³ Pa s.  For k = 10⁻²⁰ m² (Cook's 10⁻⁵ millidarcy), D = 10⁻⁸ m² s⁻¹;  a 500 m seal gives l²/D = 2.5 × 10¹³ s ≈ 0.8 Myr, so onset at about 80,000 years and full decay at about a million.  For k = 10⁻²¹ m², about 8 Myr;  for k = 10⁻²² m² and l = 1 km, about 300 Myr. ↩ ↩

Neuzil, C. E.  “Abnormal pressures as hydrodynamic phenomena.”  American Journal of Science 295(6):742–786.  1995.  A long theoretical paper by a U.S. Geological Survey scientist.  It treats abnormal pressures, meaning fluid pressures well above or below hydrostatic, as products of fluid flow rather than as relics of a time without flow, and it reviews the permeability of shales and how long a pressure takes to dissipate.  The article uses it for those figures and for its conclusion that most overpressures are kept up by ongoing geological processes.

1. 18a.

   Page 756:  “Elsewhere (Neuzil, 1994), I presented data indicating that argillaceous sediments often have largely scale-independent permeabilities between 10⁻²³ and 10⁻¹⁷ m² (roughly equivalent to K between 10⁻¹⁶ and 10⁻¹⁰ m s⁻¹) that are governed mainly by the degree of compaction.” ↩

2. 18b.

   Page 757:  “abnormal pressures would begin to suffer significant dissipation after t_D = 0.1 or t = 0.1 (S_s l²)/K;  for reasonable dimensions and permeabilities, such as those of the system analyzed by Tóth and Millar (1983), this is on the order of 10⁵ yrs.  Most abnormal pressures are thought to be much older than 10⁵ yrs.  One can readily find instances where disequilibrium has apparently persisted for 10⁷ yrs or longer, such as the western Canada sedimentary basin (Corbet and Bethke, 1992) and the U.S. Gulf Coast (Harrison and Summa, 1991).  By comparison, observing a disequilibrium system as it decays to an equilibrium state would imply rather lucky timing.  We may infer that the vast majority of disequilibrium abnormal pressures owe their existence to ongoing forcing.” ↩ ↩

3. 18c.

   Page 764:  “There is little difficulty identifying several forms of geologic forcing in the Gulf Coast, where sediments are accumulating as rapidly as 5 m per thousand yrs.  The studies mentioned above, as well as several others, indicate that compactional porosity loss alone ... is sufficient to cause the high pressures, with second-order effects from thermal expansion.”  Page 773:  “the pressure dissipation is controlled by the least permeable unit that the flow must cross to dissipate the disequilibrium.” ↩

Deming, David.  “Factors necessary to define a pressure seal.”  AAPG Bulletin 78(6):1005–1009.  1994.  A paper that works out how long a rock layer can hold back a pressure change, and how permeable the layer must be to do it.  The time grows with the square of the layer's thickness and falls as its permeability rises.  The article uses it for the figure that a seal lasting about a million years needs a permeability of 10⁻²¹ to 10⁻²³ m², which is lower than most measurements of shale permeability.

1. 19a.

   Section Abstract:  “The time over which a seal may confine a pressure transient is directly proportional to the square of the seal thickness and inversely proportional to the seal permeability.  A seal cannot be defined solely on the basis of its hydraulic resistance unless it can be shown that sufficient time has passed that steady-state conditions are approximated.  The minimum permeability needed for a geologic unit to act as a pressure seal over a time span of about 1 m.y. is in the range of 10⁻²¹ to 10⁻²³ m².  This range is generally lower than most measurements of shale permeability.” ↩ ↩

Selby, David, and Robert A. Creaser.  “Direct radiometric dating of hydrocarbon deposits using rhenium-osmium isotopes.”  Science 308(5726):1293–1295.  May 27, 2005.  A Science report that dated oil in the Alberta oil sands by rhenium-osmium isotopes, a method that reads an age from the ratios of rhenium and osmium isotopes in a sample.  It gives 112 million years for when the oil arrived, which does not support models that put oil generation and migration in the Late Cretaceous.  The authors also say their samples scatter more than their measurement errors and that the mechanism is not fully known.  The article uses it because the result contradicted the prior basin model rather than confirming it.

1. 20a.

   Page 1293:  “Rhenium-osmium (Re-Os) data from migrated hydrocarbons establish the timing of petroleum emplacement for the giant oil sand deposits of Alberta, Canada, at 112 +/- 5.3 million years ago.  This date does not support models that invoke oil generation and migration for these deposits in the Late Cretaceous.  Most Re-Os data from a variety of deposits within the giant hydrocarbon system show similar characteristics, supporting the notion of a single source for these hydrocarbons.  The Re-Os data disqualify Cretaceous rocks as the primary hydrocarbon source but suggest an origin from older source rocks.”  The age is a multi-sample isochron and assumes a shared initial ¹⁸⁷Os/¹⁸⁸Os ratio and no gain or loss of Re or Os since formation; it depends on the ¹⁸⁷Re decay constant. ↩ ↩

2. 20b.

   Page 1294:  all data except Provost, 116 ± 27 Ma (n = 24, MSWD = 21), initial ¹⁸⁷Os/¹⁸⁸Os 1.40 ± 0.56;  seventeen samples sharing an initial ratio of 1.4–1.5, 111.6 ± 5.3 Ma (MSWD = 2.2), initial 1.43 ± 0.11;  eight others, 126 ± 35 Ma.  “For the requirements of an isochron to be met, the sample set must have formed at the same time, having the same initial Os isotope ratio and not having experienced disturbance by the gain or loss of Re and/or Os since formation.”  “The high MSWD value (21) for the regressions indicates that scatter about the regression exists in excess of analytical uncertainties that relate to geological processes.”  “the specific mechanisms of isotopic resetting and equilibration for Re and Os isotopes in migrated hydrocarbons are not fully known.”  Page 1295:  the initial ratio of about 1.4 against seawater 0.3–0.6 requires a source more than 100 Myr older than 112 Ma, and.  “preclude[s] Cretaceous shale as a source”. ↩ ↩

Finlay, A. J. et al.  “Re-Os geochronology and fingerprinting of United Kingdom Atlantic margin oil: temporal implications for regional petroleum systems.”  Geology 39(5):475–478.  2011.  A 2011 study that dated eighteen oils from the UK Atlantic margin by rhenium-osmium isotopes and found an age of 68 million years, plus or minus 13.  The article uses it because that age agrees with the basin models and with argon-argon dates of oil generation.

1. 21a.

   Section Abstract:  “The Re-Os data for the 18 oils yield an age (68 ± 13 Ma) that agrees with both the relative (basin models) and absolute (Ar-Ar geochronology) timing of oil generation, indicating that that Re-Os oil geochronology records oil generation events.” ↩ ↩

Grosjean, E. et al.  “Origin of petroleum in the Neoproterozoic-Cambrian South Oman Salt Basin.”  Organic Geochemistry 40(1):87–110.  2009.  A geochemical study of oils and rock samples from the South Oman Salt Basin, by researchers at the Massachusetts Institute of Technology and Newcastle University.  It uses molecular fossils (biomarkers) and carbon isotopes to match oils to the Huqf Supergroup rocks they came from, and it finds little molecular evidence that the older Nafun Group contributed much oil.  The article uses it for the claim that these are the world's oldest known commercial oil deposits.

1. 22a.

   Page 87:  “The South Oman Salt Basin (SOSB) is host to the world's oldest known commercial deposits.  Most of the South Oman oils have been proven to be associated with the source rocks of the Neoproterozoic to Cambrian Huqf Supergroup.” ↩ ↩

2. 22b.

   Pages 87–88, section 2.1:  Ash beds within the basal A3C unit date to about 543 Ma, and a 541 Ma horizon that.  “approximates the Ediacaran–Cambrian boundary”.  The Huqf Supergroup was.  “deposited on basement rocks of ca. 840 to 810 Ma age”.  Fig. 1 places the Nafun and Abu Mahara source intervals below about 635 Ma. ↩

Jackson, M. J. et al.  “Hydrocarbon shows and petroleum source rocks in sediments as old as 1.7 × 10⁹ years.”  Nature 322:727–729.  1986.  A research report that found oil formed in place in rocks about 1.4 billion years old in northern Australia, where earlier reports of such oil were under 1 billion years old.  The oil's makeup fits origin from prokaryotes, single-celled microbes without a cell nucleus.  The article uses it as an example of oil in the Precambrian, the rock record older than the first abundant fossils, which young-earth creationists place before the Flood.

1. 23a.

   Section Abstract:  “We report the discovery of indigenous 'live' oil in ∼1.4-Gyr-old rocks in the McArthur Basin of northern Australia.  Previously reported occurrences of indigenous Precambrian oil are < 1 Gyr old.  Potential petroleum source rocks in the McArthur Basin range in age from 1.4 to 1.7 Gyr ... The hydrocarbon composition of the oil is consistent with a derivation from organic matter of prokaryotic origin.” ↩ ↩

Peters, Kenneth E., and J. Michael Moldowan.  The Biomarker Guide: Interpreting Molecular Fossils in Petroleum and Ancient Sediments.  Englewood Cliffs: Prentice Hall.  1993.  A reference book on biomarkers, the molecular fossils that living things leave in oil and ancient sediments.  The article uses it for Alfred Treibs' 1936 finding that the porphyrins in petroleum come from chlorophyll.

1. 24a.

   Page 45:  “Treibs (1936 and references therein) showed the link between chlorophyll-a in living photosynthetic organisms and porphyrins in petroleum, thus, providing the first strong evidence for an organic origin of petroleum.  During diagenesis and catagenesis, a wide variety of chlorophyll-related pigments ... are converted to various products, including three common constituents in petroleum:  porphyrins and the acyclic diterpanes pristane and phytane.” ↩ ↩

Gold, Thomas.  “The deep, hot biosphere.”  Proceedings of the National Academy of Sciences 89:6045–6049.  1992.  A short paper by Thomas Gold of Cornell University that proposes bacteria live deep in the Earth's crust, fed by chemicals carried up from below, and that they may have added biological molecules to rocks and oil.  The article uses it as the best-known abiotic theory of oil, and as the source of the paper's statement that bacterial hopanoids (molecules from bacterial cell walls) occur in every one of several hundred samples of oil, coal and kerogen examined.

1. 25a.

   Page 6046:  “hopanoids ... have however been found in all of the several hundred samples of oil, coal, and kerogen ... examined by Ourisson et al. (7).  These authors note the widespread or apparently ubiquitous presence of these molecules in the sedimentary rocks, and they give an estimate of the total quantity as of the order of 10¹³ or 10¹⁴ tons, more than the estimated 10¹² tons of organic carbon in all living organisms on or near the surface.”  Page 6047:  “It is the finding of apparently undegraded oil that nevertheless contained biomolecules that had been considered as the most compelling evidence for a biological origin of the oil itself.  This consideration would no longer be valid”.  Gold's condition: the point would no longer hold if a deep biosphere added them. ↩ ↩ ↩

Etiope, Giuseppe, and Barbara Sherwood Lollar.  “Abiotic methane on Earth.”  Reviews of Geophysics 51:276–299.  2013.  A review article that surveys the ways abiotic methane (methane formed without living matter) arises in the Earth, and how to tell it from biological methane.  The article uses it for the limits on abiotic methane: it is not found in economically exploitable reservoirs, apart from rare and controversial exceptions, and it is far less than 1 percent of the methane in most oil and gas fields.

1. 26a.

   Page 276:  “Abiotic (or abiogenic) CH₄, formed by chemical reactions that do not directly include organic matter, is produced in much smaller amounts on a global scale, and is not found in economically exploitable reservoirs, apart from rare and controversial exceptions.” ↩

2. 26b.

   Page 282:  “A systematic review by Jenden et al. [1993] shows that, at least up to the early 1990s, commercial accumulations of abiotic CH₄ have not been discovered by the petroleum industry, and that far less than 1% of CH₄ in most oil and gas fields is abiotic.” ↩ ↩

3. 26c.

   Page 282:  “The genetic zonation of CH₄ based on the isotopic composition of carbon (¹³C/¹²C) and hydrogen (²H/¹H) was introduced by Schoell [1980].  The δ¹³C vs δ²H diagram or CD diagram [e.g., Tissot and Welte, 1984;  Whiticar, 1999], has provided a fundamental framework to evaluate the origin of CH₄.” ↩

Matthews, John.  “The Origin of Oil—A Creationist Answer.”  Answers Research Journal 1:145–168.  2008.  A paper in Answers in Genesis's peer-reviewed journal, by John Matthews, that finds severe problems with both the biological and the abiotic origin of oil.  It proposes a third model, which it calls 'theobaric' (made by God), in which oil existed before the Flood and moved into its reservoirs during it, because neither standard model fits a young Earth.  The article cites it as the creationist journal's own proposal for a third model.

1. 27a.

   Section Abstract:  “To try and resolve the issue whether oil is biogenic ... or abiogenic ... a Hedberg Conference recently took place.  The issue was not resolved.  This suggests that a third alternative is needed, especially as neither model fits into a young-earth scenario. ... I have called it the 'theobaric' model, meaning made by God.  The oil existed in pristine state before the Flood, and moved during the Flood into the reservoirs where we now find it.”  Section Body:  The author writes:  “A few percent of certain alkanes may be of a biogenic origin, but it is misleading to say that these are 'fingerprints' telling us about the origin of oil.” ↩ ↩

Silvestru, Emil.  “The Canadian oil sands.”  Creation Ministries International.  2010.  A 2010 website article on the Creation Ministries International site by Emil Silvestru, based on the rock layers under the Canadian oil sands as he saw them from a boat on the Athabasca River.  He argues that the layers lie flat with no sign of erosion between the sands and the rock below, so the 260 million evolutionary years of missing time may not be real.  The article cites it for the author's view that the abiotic theory may well be correct and that oil could have come from deep in the Earth.

1. 28a.

   Section A creationist alternative:  “If the abiogenic theory is correct—and there are many reasons why that may be the case—the source of oil can be placed deep inside the earth, in areas that have never been directly affected by the Genesis Flood waters.  As the sediments of the Flood accumulated and because plate tectonics was now in place, oil started its migration along deep fault lines in the crust.” ↩ ↩

Hunt, John M.  Petroleum Geochemistry and Geology.  San Francisco: W.H. Freeman.  1979.  A textbook of petroleum geochemistry, the chemistry of how oil and gas form from organic matter in rock.  The article uses it for the carbon budget, which sets the organic carbon in sedimentary rocks against the carbon in petroleum.

1. 29a.

   Page 23:  “If the 10,700 × 10¹⁸ grams of organic carbon in clays and carbonates (Table 2-4) is multiplied by the weight ratio of hydrogen to carbon in sediments (6/82), there is, stoichiometrically, 800 × 10¹⁸ grams of hydrogen available to form oil.  This is about 6,000 times more than the hydrogen in all the petroleum accumulations of all reservoir rocks of the world.”  Coal is excluded from this figure. ↩ ↩

2. 29b.

   Page 22:  “If we assume that most oil forms from organic matter, then only 2 percent of the carbon in sedimentary rocks eventually becomes the carbon of petroleum, and less than 0.5 percent of the latter finds its way to a reservoir accumulation that survives through geologic time.  This is an efficiency of 0.01 percent from starting material to product.”  Page 27:  “The ratio of petroleum carbon in fine-grained nonreservoir rocks to petroleum carbon in commercial reservoirs is about 240 to 1.  The ratio of organic carbon in sedimentary rocks to petroleum carbon is about 11,000 to 1.” ↩

3. 29c.

   Page 334:  Reports Dow 1977b's twelve Louisiana wells at a common gradient of 2.5 °C per 100 m:  “Initiation of oil generation (0.6 R₀) is around 18,300 ft (5,578 m) or 164°C (327°F) in the Pliocene, 11,800 ft (3,597 m) or 113°C (235°F) in the Oligocene, and 8,100 ft (2,469 m) or 84°C (183°F) in the Cretaceous of this area.  Higher temperatures are required in the younger rocks, compared to the older rocks, to reach equivalent maturities.  The variations in slope in Figure 7-42 are caused by differences in burial time.”  Pages 396–397:  The Pleistocene-reservoired Eugene Island oil.  “has a calculated age of Middle Miocene”.  “the oils in the sediments younger than Miocene are rarely indigenous.” ↩

Brooks, J. D., and J. W. Smith.  “The diagenesis of plant lipids during the formation of coal, petroleum and natural gas—II. Coalification and the formation of oil and gas in the Gippsland Basin.”  Geochimica et Cosmochimica Acta 33(10):1183–1194.  1969.  A 1969 laboratory paper, the second part of a study of how plant lipids turn into coal, petroleum and gas, applied to the Gippsland Basin.  Its authors heated coal and its extracts with water in stainless steel tubes to speed up reactions that take millions of years in sediments.  The article uses it as the starting point of the creationist case for fast oil, and checks that case against the authors' own stated purpose.

1. 30a.

   Page 1185:  The coals and fractions.  “were each separately heated with water in stainless steel tubes to temperatures in the range 210–330°C for several days;  in some cases clay minerals were added.  n-Alkanes and other types of hydrocarbons were formed, the yields being greater at the higher temperatures.”  Page 1187:  “the carbon content increased from 65.3 to 82.8%, and the reflectivity of the coal from 0.18 to 1.05%, equivalent to the natural conversion of brown coal to high-volatile bituminous coal”.  “In all the experiments a pressure of gas was noted when the cooled reaction tubes were opened”.  The gas, mainly methane to hexane.  Pages 1186, 1190:  Specific runs: 210 °C for 5 days gave small but distinct changes; 330 °C for 3 days gave 40 times the n-alkane yield; esters at 330 °C for 5 days gave 10% n-alkanes, or 30% with bentonite. ↩

2. 30b.

   Page 1185:  “A main purpose of the investigation was to accelerate diagenetic reactions of sedimentary organic matter and to produce in 2–5 days the effects which result from the same organic chemical reactions occurring at lower temperatures in sediments during millions of years.”  “Temperatures of 100°C are not uncommon at depths of about 8000 ft in sedimentary basins and it can be reasonably assumed that further increase of temperature to the range used in the laboratory studies merely increases the rate of sedimentary organic reactions.” ↩

Snelling, Andrew A.  “The recent origin of Bass Strait oil and gas.”  Creation 5(2):43–46.  1982.  A magazine article from Creation Ministries International arguing that the oil and gas under Bass Strait formed by deep, rapid burial of coal and are still forming.  It reviews the geology of the Gippsland Basin and its Latrobe Group coals, and concludes that the oil is of recent origin.  The article uses it as the creationist case for fast oil at Bass Strait, and quotes its wording about rapid burial.

1. 31a.

   “Using conditions which would duplicate rapid burial of brown coal, thermal treatment of the Yallourn and Morewell brown coals in the presence of water, brought about an increase in carbon content corresponding to a conversion to a high-volatile bituminous (black) coal, accompanied by the formation of oil (liquid and gaseous hydrocarbons) from the contained waxes and leaf, pollen, and spore cuticles, all in a matter of 2–5 days!”  Snelling attributes this to "Brooks and Smith, 1969".  It is a close paraphrase-splice of the paper's pp. 1193–1194 conclusion with the p. 1185 "2–5 days", not a verbatim sentence of it, and "duplicate rapid burial" is Snelling's phrase, not theirs (the paper spells "Morwell" without the first e). ↩

Lewan, M. D. et al.  “Generation of oil-like pyrolyzates from organic-rich shales.”  Science 203:897–899.  1979.  A paper in Science by three authors, reporting that heating organic-rich shale in water made products like natural crude oil.  The article uses it as the start of the hydrous-pyrolysis work, which it says Michael Lewan's group at Amoco reported in 1979.

1. 32a.

   Section Abstract:  “Pyrolyzates similar to natural crude oils were generated from organic-rich shales by hydrous pyrolysis.  With this type of pyrolysis it is possible to make more sophisticated correlations between crude oils and their source rocks, evaluate the hydrocarbon potential of a source rock, and elucidate the variables involved in the natural oil-generating process.” ↩

Elliott, Douglas C. et al.  “Process development for hydrothermal liquefaction of algae feedstocks in a continuous-flow reactor.”  Algal Research 2(4):445–454.  2013.  Section Abstract:  “relatively low temperature (350 °C) in a continuous-flow, pressurized (sub-critical liquid water) environment (20 MPa).”  A bench-scale study of a continuous-flow reactor that turns wet algae into a biocrude oil.  It reports high conversion at 350 °C and 20 MPa, with slurries of up to 35 percent dry solids by weight.  The article cites it as its industry example of wet algae becoming crude oil at 350 °C. ↩

Thomas, Brian.  “One-Hour Oil Production?”  Institute for Creation Research.  Jan 13, 2014.  A short web article by Brian Thomas for the Institute for Creation Research, a creationist ministry, about a laboratory run that made oil from algae in about an hour at 350 °C.  The article quotes its headline to show that an industrial algae reactor makes oil in under an hour, at 350 °C.

1. 34a.

   The source is the PNNL hydrothermal liquefaction programme (Elliott et al. 2013, Algal Research 2:445).  “Simply heat pea-green algal soup to 662°F (350°C) at 3,000 psi for almost 60 minutes.”  The programme's open design report (Jones et al., PNNL-23227, March 2014, Table 3, p. 11) gives equivalent residence times of 15 to 27 minutes in the continuous reactor, so "almost 60 minutes" if anything overstates the time the reactor needed.  “These lab experiments clearly show oil can form fast.  But, what they can't demonstrate is whether this process can in fact extend over a million years.” ↩

Simoneit, B. R. T., and P. F. Lonsdale.  “Hydrothermal petroleum in mineralized mounds at the seabed of Guaymas Basin.”  Nature 295:198–202.  1982.  A research paper on petroleum dredged from hydrothermal mounds on the sea floor of Guaymas Basin in the Gulf of California.  It found gasoline-range hydrocarbons and mostly residual, asphalt-like material, and the two bitumen samples had very different boiling ranges.  The article uses it for the claim that the Guaymas oil formed at high temperatures and was quenched by hydrothermal fluid.

1. 35a.

   Section Abstract, page 198:  “Both samples contain polynuclear aromatic hydrocarbons and olefins, which indicate formation at pyrolytic temperatures.  The overall compositional data indicate an origin from biological detritus by thermal alteration and rapid quenching by hydrothermal removal, followed by condensation at the seabed.” ↩ ↩

Simoneit, Bernd R. T. et al.  “Weathering and biodegradation of hydrothermal petroleum in the north rift of Guaymas Basin, Gulf of California.”  Revista Mexicana de Ciencias Geológicas 36(2):159.  2019.  A chemical study of oil and sediment from the north rift of the Guaymas Basin, an actively spreading ocean basin in the Gulf of California.  It analysed cores from a 1980 cruise and samples taken by the submersible Alvin in 1985, and found severe biodegradation in the exposed samples, in a rift that has been dormant for about 3000 years.  The article uses it for the point that the exposed Guaymas oil is now heavily biodegraded.

1. 36a.

   Section Abstract:  “The resulting mounds are laden with the youngest hydrothermal petroleum known to date.  The north rift hydrothermal system has been dormant for ~ 3000 years ... The chemical composition of this petroleum indicates severe biodegradation for exposed samples.” ↩

Waples, Douglas W., and Shengyu Yang.  “A method for assigning pre-exponential factors for kerogen kinetics, calibrated with Easy%RoDL, and comparison with EASY%Ro.”  Advances in Geo-Energy Research 7(1):1–6.  2023.  A journal article that tests how fast the chemical reactions that make oil and gas run, using 11 source-rock data sets from both natural burial and laboratory heating.  The best single frequency factor for the industry's EASY%Ro model is 10¹³ per second, and the newer Easy%RoDL model gives 2 × 10¹⁴ per second.  The article uses the EASY%Ro figure as its frequency factor.

1. 37a.

   Section Abstract, page 1:  “The single best A factor for hydrocarbon-generation when using EASY%Ro is 1e13 s⁻¹.” ↩

Clarey, Tim.  “Rapidly Forming Oil Supports Flood Time Frame.”  Institute for Creation Research.  Feb 28, 2014.  A 2014 Institute for Creation Research article by Tim Clarey, a Research Associate there with a Ph.D. in geology.  It argues that oil could have formed quickly after the Flood, citing a laboratory result that porphyrin can be made in as few as 12 hours and a report that algae were turned into crude oil in under an hour.  The article uses it for its timing claim that natural generation could have occurred in as few as 100 years after the Flood.

1. 38a.

   “engineers at the U.S. Department of Energy's Pacific Northwest National Laboratory reported they were able to transform harvested algae into crude oil in less than one hour!  There is no reason to think this process could not have occurred naturally in as few as 100 years after the Flood.”  The article also asserts that "any non-biodegraded oil reservoirs in the world today must be recently generated and freshly recharged." ↩

Henry, Allison A., and Michael D. Lewan.  “Comparison of kinetic-model predictions of deep gas generation.”  USGS Digital Data Series 67, Geologic Studies of Deep Natural Gas Resources, Chapter D.  Edited by T. S. Dyman and V. A. Kuuskraa.  2001.  A chapter in a U.S. Geological Survey volume on deep natural gas, comparing six published kinetic models of gas generation under two heating rates.  It tabulates the Behar et al. 1997 kerogen gas yields (Table 2, p. 5) and the Pepper & Corvi 1995 Gaussian activation-energy distributions (Table 4a, p. 7).  The article uses its two gas kinetic sets as an independent check on the 4,500-year figure.

1. 39a.

   The article ran these through its own solver: Behar et al. 1997 type-II methane kinetics (A = 5.05 × 10²⁷ per Myr) give 166/215/265 °C for 4,500 years; Pepper & Corvi organofacies B (mean Ea 66.6 kcal/mol, A = 6.84 × 10³¹ per Myr) gives 173/216.  These are gas kinetics and are used only as an independent check. ↩

Sweeney, Jerry J., and Alan K. Burnham.  “Evaluation of a simple model of vitrinite reflectance based on chemical kinetics.”  AAPG Bulletin 74(10):1559–1570.  1990.  A journal article that tests a chemical-kinetics model of vitrinite reflectance, the usual measure of thermal maturity.  The model's reaction rates are checked across laboratory and geologic time scales, and the authors say it applies to reflectance from 0.3 to 4.5%.  The article uses it because the model says heating time matters little, so reflectance measures temperature better than time.

1. 40a.

   Page 1561:  Table 1 gives the model's activation energies and frequency factor.  “In our model, F ranges between 0 and 0.85, so the maximum value of %Ro possible with equation 1 is 4.7%”.  “the dependence on heating time is weak.”  Page 1568:  The model is stated to hold for heating rates.  “from 1°C/week in the laboratory to geologic scales.” ↩

Snelling, Andrew A.  Earth's Catastrophic Past: Geology, Creation and the Flood.  Volume 2 vols..  Dallas: Institute for Creation Research.  2009.  A two-volume creationist book from the Institute for Creation Research that applies Noah's Flood to the geologic record.  The article quotes it as the book-length creationist statement on oil, including its concession that some oil lies in Precambrian rock and its estimate that more than 85 percent of oil and gas source rocks would fall in the Flood.

1. 41a.

   Volume 2.  Page 758:  “if the Flood/post-Flood boundary is placed at approximately the Cretaceous/Tertiary strata boundary, then more than 70 percent of all the coal beds, and more than 85 percent of all the oil and gas source rocks, would have been deposited under the catastrophic conditions prevailing during the Flood.” ↩

2. 41b.

   Chapter 121, Oil Deposits:  Volume 2; the chapter runs pp. 965–976.  Page 965:  Snelling says exploration techniques.  “such as seismic surveying and the analysis of organic matter found in sedimentary rock sequences, do not really depend on the historical aspects of geology at all, but only on recognition of the structural, sedimentary, and organic petrological markers that experience has shown are associated with, and a guide to the finding of, petroleum deposits.”  Page 973:  Eight pages later the chapter names one of those markers.  “one measure that has come to be used as a guide to the potential for finding oil or gas when exploring new sedimentary sequences is the vitrinite reflectance.”  Page 967:  Repeats that oil occurs in rocks of all ages.  “except the Pleistocene and Holocene.” ↩ ↩

3. 41c.

   Volume 2.  Page 967:  Citing Jackson et al. 1986 and Dutkiewicz et al. 2003.  Page 975:  The mechanism is given on this page.  “As soon as deposition and deep burial of the organic matter had occurred, petroleum generation would have begun, especially where the waters trapped in the sediments were at the same time heated by nearby volcanic sources and magma chambers.” ↩ ↩

4. 41d.

   Volume 2.  Pages 970–971:  “Experiments have produced a concentration of 0.5 percent porphyrin (of the type found in crude oils) from plant material in just one day, so millions of years are not required ... Indeed, a crude oil porphyrin can be made from plant chlorophyll in less than twelve hours.  However, other experiments have shown that plant porphyrin breaks down in as little as three days when exposed to temperatures of only 210°C (410°F) for only twelve hours.  Therefore, the petroleum source rocks, and the crude oils generated from them, cannot have been deeply buried to such temperatures for millions of years.”  The sentence on 0.5 percent porphyrin is footnoted to DiNello & Chang 1978; the twelve-hour and 210°C sentences carry no footnote.  Clarey 2014 cites this page for the twelve-hour claim. ↩

DiNello, Robert K., and C. K. Chang.  “Isolation and modification of natural porphyrins.”  The Porphyrins, vol. I, Structure and Synthesis, Part A, 289–339.  New York: Academic Press.  Edited by David Dolphin.  1978.  Chapter 7 of a reference book on porphyrins, giving laboratory methods for isolating natural porphyrins and changing them in the lab.  The article uses it for the procedure behind the 210 °C figure: heating a chlorophyll extract in a sealed bomb for 8-12 hours to make pyrroporphyrin, a preparative synthesis rather than a test of how fast oil breaks down.

1. 42a.

   Page 328:  “One hundred grams of 'oil soluble chlorophyll' ... are dissolved in 500 ml of acetone in a large beaker and 100 ml of concentrated HCl are added to make the solution 2 N in acid.  The mixture is stirred slowly with a mechanical stirrer for 2 days. ... A 15-gm portion of the tarry pigment is placed in a large test tube (80 ml) which has been silver plated ... Sixty milliliters of 30% methanolic potassium hydroxide solution are added ... The tube is sealed in a Parr bomb and heated to 210°C for 8-12 hr. ... The yield of pure pyrroporphyrin is about 0.5 gm from 100 gm of crude chlorophyll extract.”  “Rhodoporphyrin is obtained as the major product when the pyrolysis in methanolic KOH described above is carried out at about 150°C instead of 210°C.” ↩

Mackay, John.  “Refuting the Critics: Coal, Oil, Natural Gas, and the Heat-Problem.”  YouTube, Standing For Truth.  2021.  A 2021 YouTube video by Budinsky, made for the Standing For Truth channel, in which John Mackay is interviewed.  The article treats it as the one creationist statement that addresses the heat directly.

1. 43a.

   “we know from experiments john that have been done by the csiro on oil formation and many others have done experiments on coal as well that it takes roughly 350 to 400 degrees celsius to um to actually create that oil”.  “we have made all three using simple clay experiments with no temperature emissions of any great significance at all.”  No published experiment is cited. ↩

Dickens, Harry.  “Petroleum systems do not require millions of years.”  Journal of Creation 37(3):18–21.  2023.  A short article in the creationist Journal of Creation arguing that temperature, not time, controls how fast petroleum forms, and that most oil in reservoirs formed during Noah's Flood and its aftermath.  It gives a secondary migration rate (the movement of oil from source rock to reservoir) of about 1 km per year and reuses Bruce's kinetic figure.  The article cites it for the figure caption that repeats Bruce's model.

1. 44a.

   Figure 3, page 20:  “Bitumen yield versus temperature for various times of heating based on the kinetic model of Nielsen and Barth.  After 1,000 years, significant bitumen can be generated within realizable temperatures in sedimentary basins.  (After Bruce et al.)”  Page 18:  “Temperature, rather than time, is the most important factor controlling petroleum generation.” ↩

Holland, David S. et al.  “Eugene Island Block 330 Field — U.S.A., Offshore Louisiana.”  AAPG Treatise of Petroleum Geology, Structural Traps III, 103–143.  1990 (edition of 1999).  A description of an offshore Louisiana oil and gas field, written for the AAPG (American Association of Petroleum Geologists) treatise of 1990 and reprinted online in 1999 as Search and Discovery Article 20003.  It covers the field's discovery in 1971, its more than 25 productive Pleistocene sandstones, and the more than 100 separate reservoirs they form.  The article uses it for the young age of those reservoirs, for the growth fault that is still active beneath them, and for the source-rock evidence.

1. 45a.

   “More than 25 Pleistocene sandstones are productive at depths of 701 to 3658 m (2300 to 12,000 ft).  Faulting and permeability barriers separate these sands into more than 100 oil and gas reservoirs.”  “The fault has been active since at least the early Pleistocene (2.1 MYBP) and continues to be active today.” ↩ ↩

2. 45b.

   “Pleistocene shales associated with the Block 330 reservoirs do not qualify as the source rocks for these oils because of their thermal immaturity (R_o = 0.31-0.47%) and low organic carbon content ... results are consistent with those of Young et al. (1977), who concluded that most Gulf of Mexico oils originated 2438 to 3350 m (8000 to 11,000 ft) deeper than their reservoirs, from source beds 5 to 9 million years older than the reservoirs.”  "Thermally immature" means the shales were never heated enough to turn their organic matter into oil. ↩

Morris, Henry M., and Gary E. Parker.  What is Creation Science?  San Diego: Creation-Life Publishers.  1982.  A creationist book by Henry M. Morris and Gary E. Parker.  It lists the great pressures in oil reservoirs among the evidence for a young earth.  The article uses it as the 1982 statement of that argument, which it traces back to Melvin Cook's 1966 book.

1. 46a.

   Page 284:  “an excellent textbook by evolutionist William Stansfield (1977) cites at least ten different chronometers that could be reasonably interpreted as support for a young earth.  Some of these are as follows: ... 4. The great pressures now existing in oil reservoirs could only have been sustained for a few thousand years.”  Stansfield is The Science of Evolution (Macmillan, 1977), p. 84. ↩

Dickey, Parke A. et al.  “Abnormal pressures in deep wells of southwestern Louisiana: High fluid pressures are associated with slump-type faults and shed light on processes of compaction.”  Science 160(3828):609–615.  May 10, 1968.  A study of deep oil and gas wells in southwestern Louisiana, where fluid pressures well above normal hydrostatic pressure were met at depths from 7,000 to more than 16,000 feet.  The authors tie the high pressures to growth faults, which they say kept water from escaping the shales as they were buried.  The article uses it because creationists sometimes cite it for their claim, and it says the opposite.

1. 47a.

   Page 612:  “Well A is separated from well B by a fault.  Apparently the fault completely shut off the flow of water, because the shales below 11,000 feet in well A are normally compacted.  The significance of this observation to structural geology is very great.  It means that pore water has been able to move across the bedding planes of shale hardly at all, in spite of a pressure gradient exceeding 10 pounds per square inch per foot during scores of millions of years.”  “Students of petroleum-reservoir behavior have long known that faults which cut oil reservoirs form pressure discontinuities and are therefore seals rather than channels.” ↩

2. 47b.

   Page 615:  “The growth faults seal the flow of fluids, and, down-dip from them, abnormally high pressures are found.  The shales in these intervals are less compacted than is usual at the depth at which they are buried.  The normal processes of compaction and diagenesis were arrested by the faulting.  The pore water has remained in the sediments, where it has to support part of the weight of the overburden, and its hydrostatic pressure is, therefore, much above normal.”  Page 612:  Also on this page, the paper concedes:  “Shale permeability is difficult to measure, and no reliable values have been published”.  The gap Cook and Morris filled with their own numbers. ↩

Fertl, Walter H.  “Abnormal Formation Pressures: Implications to Exploration, Drilling, and Production of Oil and Gas Resources.”  Developments in Petroleum Science 2.  Amsterdam: Elsevier.  1976.  A petroleum-industry book on abnormal formation pressures, meaning fluid pressures in rock that are higher than the normal hydrostatic pressure for its depth.  It reviews what causes them, including faults and rapid sedimentation, and it reports the 1968 Louisiana well study by Dickey and colleagues.  The article uses it to show how this industry book described that study.

1. 48a.

   Page 81:  “In an excellent paper, Dickey et al. (1968) observed that faults which transect oil reservoirs form pressure discontinuities and act as seals for zones of high fluid pressure for long periods of time.”  Page 51:  “Overpressured, undercompacted formations in many parts of the world probably owe their origin to rapid sedimentation, which trapped water in compacting clays with practically no permeability.”  Page 24:  “According to Dickey et al. (1968), the pattern of the high-pressure zones appears to be related to the peculiar patterns of faulting contemporaneous with sedimentation which are characteristic of the U.S. Gulf Coast.” ↩

Osborne, M. J., and R. E. Swarbrick.  “Mechanisms for generating overpressure in sedimentary basins: a reevaluation.”  AAPG Bulletin 81(6):1023–1041.  1997.  A review of the ways that burial and tectonic stress can raise fluid pressure in sedimentary basins, with a verdict on each.  It finds that loading during burial and changes in horizontal stress can generate large overpressures, while stress-related mechanisms are the most likely causes in many basins.  The article uses it for its verdict that overpressure from hydrocarbon generation is unproven at present, and it claims no more than that.

1. 49a.

   Section Abstract:  “Loading during burial can generate considerable overpressure due to disequilibrium compaction, particularly during the rapid subsidence of low-permeability sediments.  Horizontal stress changes can rapidly generate and dissipate large amounts of overpressure in tectonically active areas. ... Fluid volume increases associated with aquathermal expansion and clay dehydration are too small to generate significant overpressure unless perfect sealing occurs. ... The potential for generating overpressure by hydrocarbon generation and cracking must be regarded as unproven at present. ... Stress-related mechanisms are the most likely causes of overpressure in many sedimentary basins.” ↩

Ge, Xiang et al.  “Neoproterozoic-Cambrian petroleum system evolution of the Micang Shan Uplift, northern Sichuan Basin, China: insights from pyrobitumen Re-Os geochronology and apatite fission track analysis.”  AAPG Bulletin 102(8).  2018.  A study of pyrobitumen, a solid bitumen that formed as oil cracked into gas under heat, in rock from the Micang Shan Uplift in northern Sichuan Basin, China.  It dates the pyrobitumen by rhenium-osmium isotopes and sets that date beside fission-track data, which show that the rock was uplifted and eroded in the Cretaceous.  The article uses it because it applies the dating method to the oil itself and reports the scatter in its results.

1. 50a.

   Lines 35–39:  “The Re-Os isotope data imply an Early Jurassic date for pyrobitumen formation, which coincides well with age estimates from fluid inclusion data and basin modelling.”  Lines 489–494:  “Latest Triassic to the Middle Jurassic dates (ca. 205 – 173 Ma) derived from the Re-Os pyrobitumen data, especially the ~184 Ma date determined from six samples, from the Micang Shan Uplift agree well with previous basin modelling.”  Line 443:  all eleven samples give 239 ± 150 Ma with MSWD = 398.  Line 465:  the 184 ± 23 Ma age is the six-sample subset. ↩

Head, Ian M. et al.  “Life in the slow lane; biogeochemistry of biodegraded petroleum containing reservoirs and implications for energy recovery and carbon management.”  Frontiers in Microbiology 5:566.  2014.  A review by three researchers at Newcastle University on how microbes change oil in underground reservoirs.  It brings together microbiological and chemical data, and it estimates rates of bacterial breakdown at the oil-water contact from the way oil composition changes down the oil column.  The article uses it for those rates and for the claim that the breakdown has run for many millions of years, which the review itself describes as estimated from oil compositions rather than measured.

1. 51a.

   “The subsurface reservoir biodegradation fluxes ... for fresh petroleum in clastic e.g., sandstone, reservoirs are on the order of 10⁻⁴ kg/m²/year at 40°C decreasing with increasing reservoir temperature to a value close to zero, around 80°C.”  “Based on oil compositional gradients, areal oil degradation fluxes at the OWTZ of reservoirs containing heavy oil have been estimated at around 10⁻⁵ to 10⁻⁶ kg/m²/y (Larter et al., 2003).”  “continuous vertical compositional gradients in the oil columns document episodic degradation for many millions of years, suggesting that the timescales of oilfield degradation and petroleum charging are similar (Larter et al., 2003).” ↩

Computed for this article.  A 30 m oil column over 1 m² of oil-water contact at 800 kg m⁻³ holds 2.4 × 10⁴ kg;  at 10⁻⁴ kg m⁻² yr⁻¹, removing 10% takes 2.4 × 10⁷ years;  at 10⁻⁵ to 10⁻⁶ kg m⁻² yr⁻¹, 10⁸ to 10⁹.  The fluxes are inferred from compositional gradients and assumed rates, not directly measured. ↩

Ulmishek, Gregory F., and H. D. Klemme.  “Depositional controls, distribution, and effectiveness of world's petroleum source rocks.”  U.S. Geological Survey Bulletin 1931.  1990.  A U.S. Geological Survey bulletin that maps the world's petroleum source rocks by age and reports that six stratigraphic intervals (layers laid down in set spans of time) cover 35.2 percent of Phanerozoic time (the part of Earth's history with abundant fossils) and generated 91.5 percent of the original oil and gas reserves.  Klemme and Ulmishek printed the same figures in the AAPG Bulletin 75:1809–1851 in 1991.  The article uses it to show that the great oil sources sit at six levels of the rock record, not one.

1. 53a.

   Page 1:  The abstract, which the article quotes.  Page 2:  “These stratigraphic intervals represent only 35.2 percent of Phanerozoic time, but they have generated 91.5 percent of the original reserves of world oil and gas (which total about 2,200 billion BOE).” ↩

Sherwood Lollar, B. et al.  “Abiogenic formation of alkanes in the Earth's crust as a minor source for global hydrocarbon reservoirs.”  Nature 416:522–524.  2002.  A research paper in Nature that measured carbon and hydrogen isotopes in methane and higher alkanes from crystalline rock of the Canadian Shield.  Abiogenic (made without living matter) and thermogenic (made by heating buried organic matter) hydrocarbons could be told apart, and the authors ruled out a globally significant abiogenic source because economic gas reservoirs lack the isotope trend.  The article uses it to test Gold's deep-microbe answer to the biomarker problem.

1. 54a.

   Section Abstract:  “using carbon and hydrogen isotope analyses of abiogenic methane and higher hydrocarbons in crystalline rocks of the Canadian shield, we show a clear distinction between abiogenic and thermogenic hydrocarbons.  The progressive isotopic trends for the series of C1–C4 alkanes indicate that hydrocarbon formation occurs by way of polymerization of methane precursors.  Given that these trends are not observed in the isotopic signatures of economic gas reservoirs, we can now rule out the presence of a globally significant abiogenic source of hydrocarbons.” ↩

Glasby, G. P.  “Abiogenic origin of hydrocarbons: an historical overview.”  Resource Geology 56(1):85–98.  2006.  A historical review, not a new experiment, of the two theories that say oil and gas form deep in the Earth from matter that was never alive.  The review calls Gold's version invalid on thermodynamic grounds, meaning the energy rules that decide which reactions can happen.  The article uses it as a specialist's review that rejects Gold's deep gas theory.

1. 55a.

   Page 85, section Abstract:  “formation of higher hydrocarbons in the upper layers of the Earth's crust occurs only as a result of Fischer-Tropsch-type reactions in the presence of hydrogen gas but is otherwise not possible on thermodynamic grounds.  This theory is therefore invalid.  Both theories have been overtaken by the increasingly sophisticated understanding of the modes of formation of hydrocarbon deposits in nature.”  Page 95:  “First and foremost is the fact that the mantle is too oxidizing for methane to form there in abundance.  Furthermore, most volatiles including methane are transported from the mantle to the Earth's crust in magma and not by faults as required by the theory.”  Glasby leaves open that.  “serpentinization of ultramafic rocks does have the potential to produce commercial oil and gas fields.” ↩

Kenney, J. F. et al.  “The evolution of multicomponent systems at high pressures: VI. The thermodynamic stability of the hydrogen–carbon system: the genesis of hydrocarbons and the origin of petroleum.”  PNAS 99(17):10976–10981.  2002.  A theory paper with a laboratory test, by researchers from Russian institutes and a Houston gas company.  It finds that alkanes heavier than methane (the simple hydrocarbons with two or more carbon atoms) form only at pressures above about 30 kbar, roughly 100 km down, and a test using only iron oxide and marble, wet with water, made petroleum-like hydrocarbons at 50 kbar and 1500°C.  The article cites it as one of the two experiments creationists cite for abiotic oil, and it argues that the result cuts against them.

1. 56a.

   Section Abstract:  “The theoretical analyses establish that the normal alkanes, the homologous hydrocarbon group of lowest chemical potential, evolve only at pressures greater than approximately thirty kbar, excepting only the lightest, methane.  The pressure of thirty kbar corresponds to depths of approximately 100 km.”  Section Experimental section:  “At pressures below 10 kbar, no hydrocarbons heavier than methane were present.  Hydrocarbon molecules began to evolve above 30 kbar.  At 50 kbar and at the temperature of 1500°C, the system spontaneously evolved methane, ethane, n-propane ... in distributions characteristic of natural petroleum.” ↩

Kolesnikov, A. et al.  “Methane-derived hydrocarbons produced under upper-mantle conditions.”  Nature Geoscience 2:566–570.  2009.  A short research letter in which the authors heated methane and ethane in a diamond-anvil cell, a device that squeezes a sample between two diamonds, and identified the products with Raman spectroscopy, a laser method that reads molecules from the light they scatter.  Above 2 GPa and 1,000–1,500 K, methane partly turned into ethane, propane and butane, plus hydrogen and graphite, and ethane turned back into methane.  The authors say their results support the idea that heavier hydrocarbons can be made without life in the upper mantle, and the article counts the letter among the two experiments creationists cite for abiotic oil, which it says do not make oil.

1. 57a.

   Page 566:  “There is widespread evidence that petroleum originates from biological processes”.  Section Abstract:  “We show that when methane is exposed to pressures higher than 2 GPa, and to temperatures in the range of 1,000–1,500 K, it partially reacts to form saturated hydrocarbons containing 2–4 carbons (ethane, propane and butane) and molecular hydrogen and graphite.” ↩

Wieland, Carl.  “Oil not always a 'fossil fuel'.”  Creation 32(2):56.  2010.  A short magazine article in Creation arguing that some oil may come from non-living sources, and reporting Vladimir Kutcherov's claim, from the Royal Institute of Technology in Sweden, that crude oil and natural gas form without fossils.  The web version carries an addendum dated 27 September 2023 that concedes a minority of the world's oil may be inorganic.  The article uses it for a Creation Ministries author's view that the abiotic theory may well be correct.

1. 58a.

   “The controversial research has huge potential implications.  For one thing, it neutralizes the challenge from the Bible's critics that there could not have been enough creatures alive on Earth at the time of Noah's Flood to explain all the oil and gas.”  The research is Kolesnikov, Kutcherov & Goncharov 2009, a diamond-anvil experiment producing ethane to butane from methane at mantle pressures.  The article also cites Vietnam's Bach Ho field as oil pumped.  “from rocks such as granite”.  That field is a fractured-basement reservoir charged from Oligocene lacustrine source rocks, and reservoir lithology says nothing about origin. ↩

2. 58b.

   The 2023 addendum says:  “Today, most geologists, including creationists, would still consider the majority of the world's oil to be from huge amounts of organic matter buried in sedimentary layers, consistent with the biblical Flood account.  However, they would likely concede that a minority of the oil could well be attributed to inorganic sources.” ↩

Wile, Jay.  Blog post on abiotic oil.  2013.  A 2013 blog post by Jay Wile on abiotic oil, the idea that oil comes from sources that are not living.  The article cites it in its discussion of where creationists disagree about oil.

1. 59a.

   “When it comes to coal, I think there is strong evidence that it is truly a fossil fuel.  When it comes to oil, however, there is strong evidence that at least some of its components come from processes that are not related to living things at all.”  Of Kenney 2002 and Kolesnikov 2009, Wile wrote:  “Notice that in both studies, the authors don't claim to have made oil.  They just claim to have made some of the components of oil ... Right now, however, the best we can say is that the concept of abiotic oil requires a lot more research.” ↩

Snelling, Andrew A.  “Responding to BioLogos' Tactics on Their Opposition to Young-Earth Flood Geology.”  Answers in Genesis.  Jun 18, 2025.  Part 1 of a series called Flood Geology and the Grand Canyon: What the Evidence Really Does Say.  It answers a sentence in the Kregel volume Grand Canyon, Monument to an Ancient Earth, which says that petroleum "has historically been discovered using methods arrived at wholly from an old earth viewpoint."  The article quotes his claim that the ways of finding oil have nothing to do with whether the earth is billions of years old.

1. 60a.

   Quoted as the article prints it. ↩

Al-Hajeri, M. M. et al.  “Basin and petroleum system modeling.”  Oilfield Review 21(2):14–29.  Schlumberger.  2009.  A review by fourteen authors from Schlumberger's magazine Oilfield Review, on basin and petroleum system modeling.  Two of its authors also wrote the standard textbook, Hantschel and Kauerauf's Fundamentals of Basin and Petroleum Systems Modeling (Springer, 2009).  The article cites it, as an industry source, for the limits of seismic interpretation and for what a basin model needs.

1. 61a.

   Page 14:  “The term 'petroleum system' is now commonly used within the industry.”  The article quotes from this page. ↩

2. 61b.

   Page 18:  “Also required are kinetic parameters for the thermal conversion of the source-rock kerogen to petroleum.”  Page 19:  “Key inputs for building a burial history include sedimentation rate, compaction, uplift, erosion and depositional environment. ... Modeling the petroleum potential of a basin requires reconstruction of the temperature over geologic time and across the basin. ... boundary conditions are sediment/water interface temperatures throughout geologic time which, along with paleoheat-flow estimates, are required.” ↩

3. 61c.

   Page 19:  The caption of the events chart reads:  “Because the reservoir ... before the end of Jurassic time, its hydrocarbons must be preserved for more than 180 million years to remain a viable prospect.” ↩

Magoon, Leslie B., and James W. Schmoker.  “The Total Petroleum System — the natural fluid network that constrains the assessment unit.”  USGS World Petroleum Assessment 2000, Digital Data Series 60.  2000.  Chapter PS of the U.S. Geological Survey's 2000 world assessment, restating an earlier account by Magoon and Dow from 1994 (AAPG Memoir 60).  It defines a total petroleum system as the source, reservoir, seal and overburden rocks and the processes that move and trap oil and gas, and it names and maps 159 of the largest such systems in the world.  The article uses it for the USGS's statement that burial-history modeling and kinetics give the best information on when oil forms, moves and collects.

1. 62a.

   Chapter PS, page 13:  “Sixth, the best information for generation-migration-accumulation is from source rock burial modeling and kinetics. ... Seventh, preservation time is defined as that time when generation-migration-accumulation ends and continues to present.”  Chapter PS, page 8:  “The critical moment is the time that best depicts the generation-migration-accumulation of hydrocarbons in a TPS.” ↩

Morton, Glenn R.  Why I left Young-Earth Creationism.  2000.  A personal account by Glenn Morton, a geophysicist who processed seismic data for Atlantic Richfield, of why he left young-earth creationism.  The article prints his poll of ICR graduates who worked in the oil industry as an anecdote, not as evidence.

1. 63a.

   “Nothing that young-earth creationists had taught me about geology turned out to be true.  I took a poll of my ICR graduate friends who have worked in the oil industry.  I asked them one question.  'From your oil industry experience, did any fact that you were taught at ICR, which challenged current geological thinking, turn out in the long run to be true?' ... One man, Steve Robertson, who worked for Shell grew real silent on the phone, sighed and softly said 'No!'  A very close friend that I had hired at Arco, after hearing the question, exclaimed, 'Wait a minute.  There has to be one!'  But he could not name one.” ↩

Losh, S. et al.  “Reservoir fluids and their migration into the South Eugene Island Block 330 reservoirs, offshore Louisiana.”  AAPG Bulletin 86(8):1463–1488.  2002.  A 2002 study of the oil and fluids in the South Eugene Island Block 330 reservoirs, the same Louisiana field that Holland's description covers.  It compares biodegraded oils (oils that microbes have partly broken down) with unbiodegraded ones, and sets oil chemistry beside reservoir pressures to work out where the oil came from.  The article uses it for the finding that these reservoirs filled much more recently than the salt weld beneath the field.

1. 64a.

   Section Abstract:  “Distribution of biodegraded vs. unbiodegraded oils indicates the reservoirs filled much more recently than formation of the salt weld beneath the field. ... Hydrocarbon distribution, combined with oil chemistry and reservoir pressures, indicate reservoirs filled from fault systems on both the north and south sides of the field.” ↩

IPCC.  “Solid Waste Disposal.”  2006 IPCC Guidelines for National Greenhouse Gas Inventories 5.  2006.  Chapter 3 of volume 5 of the IPCC's 2006 guidelines for national greenhouse-gas inventories, on solid waste disposal sites.  It gives the decay rates that such waste is assumed to follow.  The article uses it for the landfill half-lives, from about 3 years for wet food waste to 35 for wood and paper.

1. 65a.

   Chapter 3, page 16:  “Measurements from SWDS in Argentina, New Zealand, the United States, the United Kingdom and the Netherlands support values for t½ in the range of approximately 3 to 35 years ... The most rapid rates (k = 0.2, or a half-life of about 3 years) are associated with high moisture conditions and rapidly degradable material such as food waste.  The slower decay rates (k = 0.02, or a half-life of about 35 years) are associated with dry site conditions and slowly degradable waste such as wood or paper.” ↩

Katz, Barry J.  “Microbial processes and natural gas accumulations.”  The Open Geology Journal 5:75–83.  2011.  A limited overview of microbial gas, the gas that microbes make in oxygen-free settings, written by Barry Katz of the Chevron Energy Technology Company.  Its abstract estimates that microbial gas makes up more than 20 percent of the world's gas resource base, and that some single accumulations exceed one trillion cubic feet.  The article uses it for that share, and to keep rapid biogenic gas apart from the thermogenic oil it discusses.

1. 66a.

   Page 75, section Abstract:  “Individual microbial gas accumulations may be significant (> 1 Tcf ...) and collectively account for more than 20% of the global gas resource-base, dominating in some individual basins.” ↩