Burial destruction

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Exploring for Oil and Gas Traps
Series Treatise in Petroleum Geology
Part Predicting the occurrence of oil and gas traps
Chapter Predicting preservation and destruction of accumulations
Author Alton A. Brown
Link Web page
Store AAPG Store

Given the strong economic control of petroleum type on development of an accumulation, the conversion of oil to gas or dilution of gas by nonhydrocarbon components in the deep burial environment may make an accumulation uneconomic and, from an exploration point of view, “destroyed.” The following burial processes destroy accumulations by altering the properties of the petroleum:

  • Gasification
  • Gas destruction
  • Gas dilution

Gasification

Gasification is the conversion of oil to gas resulting from thermal cracking. It primarily takes place during burial. If oil is spilled from a trap by gas displacement during gasification, the oil may occur in economic accumulations updip along the migration pathway.[1]

Predicting and recognizing gasification

The following characteristics can help us predict and recognize gasification.

  • Geohistory analysis with proper gasification kinetics can usually predict at what depth accumulations have been gasified.
  • As a rule of thumb, oil should not be expected at subsurface temperatures > temperature::150°C or a maturation level much above 1.3% Ro. Dry gas accumulations can occur at shallower depths, but oil is not likely at greater depths.
  • Gasification of oil in reservoirs is associated with the formation of pyrobitumen.[2]
  • Displacement of oil from a trap by gas is associated with asphaltene precipitates and/or relatively unaltered oil stain.
  • Absence of an oil leg in the trap prior to charging by gas is indicated by the absence of oil stain with heavy molecular components.
  • In accumulations that have been gasified, the presence of pyrobitumen can significantly reduce reservoir permeability due to gas or condensate.

Gas destruction

Methane is the most thermodynamically stable hydrocarbon in sedimentary basins.[3] Methane apparently can be destroyed only by oxidation. The most common form of oxidation in the burial environment is thermogenic sulfate reduction.[4] The presence of oxidized iron can also remove methane at high temperatures.

Studies by Barker and Takach.[5] indicate water can oxidize methane to carbon dioxide and hydrogen gas at temperatures as low as temperature::200°C, assuming systems are at thermo-dynamic equilibrium. Where oxygen fugacity is buffered at modestly reducing conditions, methane is calculated to remain stable to temperatures > temperature::400°C[6]

Predicting gas destruction

It is not the destruction of methane as much as the lack of economic accumulations which occurs at higher maturation levels. Methane occurs in fluid inclusions from lower crustal depths, and shows of methane are not unusual where drilling through low-grade metamorphic rocks—even those at a grade high enough to contain graphite instead of kerogen (R0 > 8%). For example the Shell Barret #1 well in Hill County, Texas, had a 30-minute methane flare at over depth::13,000 ft depth in rock described as dolomite and calcite marble with graphitic inclusions.[7]

The following characteristics can help us predict and recognize gas destruction:

  • Economic gas accumulations become more unusual with maturation levels > 2.8% Ro.[8] This is the traditional base of the gas preservation zone.
  • The major gas accumulation with the highest well-documented maturity level where charging occurred before or during exposure to the high temperatures occurs at a maturation level 3.5–3.8% Ro equivalent (Wilburton field, Oklahoma).[9]

Gas dilution

Carbon dioxide, hydrogen sulfide, and nitrogen can constitute a significant percentage of natural gas from some accumulations. In some cases, natural gas is uneconomic due to the high nonhydrocarbon gas content.

Although low concentrations of carbon dioxide can be derived from organic sources or byproducts of silicate reactions at moderate temperatures[10] high concentrations of carbon dioxide are usually associated with igneous intrusion or regional heating of impure limestones.[11]

Hydrogen sulfide concentration increases with depth in gas reservoirs with anhydrite, indicating that it, too, is a product of higher maturity.[4] The methane is reacting with the sulfate to form hydrogen sulfide and carbon dioxide gas. The reaction is probably kinetically controlled.

The origin of nitrogen gas is not well characterized. In nonpetroleum basins, nitrogen may have high concentration because no other gas is present to dilute it. High-nitrogen gas in thermally mature basins is possibly from coal sources[12] or from the mantle or deep crust.[13]

Predicting burial destruction

The following characteristics can help us predict and recognize burial destruction.

  • Analyzing geohistory or mapping maturation indicators can identify reservoir maturation levels where methane accumulations may be uneconomic. Most sizable gas accumulations occurring at maturation levels > 2.8% Ro have thick claystone seals that help preserve the accumulation.
  • Presence of intrusives in the fetch area can indicate a potential for carbon dioxide dilution.[14]
  • If reservoir rocks are associated with evaporite cements or beds, expect hydrogen sulfide if the reservoir is exposed to temperatures > temperature::150°C and iron is not present to remove the hydrogen sulfide.
  • Nitrogen is released during the late stages of coal maturation.[15] Therefore, if a prospect is charged by a type III source rock only during its late maturation stage (Ro > 2.5%), nitrogen dilution is possible. High nitrogen gas content is also characteristic of evaporative settings and hydrocarbon-poor basins.
  • Nonhydrocarbon gas concentrations in mature basins can be estimated from evaluating regional gas concentration trends.

The table below summarizes techniques that help us predict hydrocarbon destruction during burial.

Process Prediction techniques
Gasification
  • Geohistory analysis
  • Mapping maturation indicators (no oil, where reservoir Ro > 1.3%)
Gas destruction
  • Geohistory analysis
  • Mapping maturation indicators (gas unlikely where reservoir Ro> 2.8%)
Gas dilution Identified by Indicates potential for
  • Intrusives in fetch area
  • Evaporite cements or beds at depths where temperature > temperature::150°C
  • Gas sourced from coal, high thermal maturity
  • Low methane charge
  • Carbon dioxide
  • Hydrogen sulfide
  • Nitrogen
  • Carbon dioxide, nitrogen

See also

References

  1. ↑ Gussow, W. C., 1954, Differential entrapment of oil and gas: a fundamental principle: AAPG Bulletin, vol. 38, p. 816–853.
  2. ↑ Tissot, B. P., D. H. Welte, 1984, Petroleum Formation and Occurrence, 2 ed.: New York, Springer-Verlag, 699 p. 460–461
  3. ↑ Hunt, J. M., 1979, Petroleum Geochemistry and Geology: San Francisco, W. H. Freeman, 617 p.
  4. ↑ 4.0 4.1 Krouse, H. R., 1979, Stable isotope geochemistry of non-hydrocarbon constituents of natural gas: Proceedings of the Tenth World Petroleum Congress, vol. 4, p. 85–91.
  5. ↑ Barker, C., and N. E. Takach, 1992, Prediction of natural gas composition in ultradeep sandstone reservoirs: AAPG Bulletin, vol. 76, p. 1859–1873.
  6. ↑ Green, D. H., T. J. Falloon, and W. R. Taylor, 1987, Mantle-derived magmas—roles of variable source peridotite and variable C-H-O fluid compositions, in Mysen, B. O., ed., Magmatic Processes: Physiochemical Principles: The Geochemical Society Special Publication No. 1, p. 139–153.
  7. ↑ Rozendal, R. A., and W. S. Erskine, 1971, Deep test in Ouachita structural belt of Central Texas: AAPG Bulletin, vol. 56, p. 2008–2017.
  8. ↑ Bartenstein, H., 1980, Coalification in NW Germany: Erdöl und Kohle-Erdgas-Petrochemie: vol. 33, p. 121–125.
  9. ↑ Hendrick, S. J., 1992, Vitrinite reflectance and deep Arbuckle maturation at Wilburton field, Latimer County, OK: Oklahoma Geological Survey Circular 93, p. 176–184.
  10. ↑ Smith, J. T., and S. N. Ehrenberg, 1989, Correlation of carbon dioxide abundance with temperature in clastic hydrocarbon reservoirs: relationship to inorganic chemical equilibrium: Marine and Petroleum Geology, vol. 6, p. 129–135., 10., 1016/0264-8172(89)90016-0
  11. ↑ Farmer, R. E., 1965, Genesis of subsurface carbon dioxide, in A. Young, and J. Galley, eds., Fluids in Subsurface Environments: AAPG Memoir No. 4, p. 378–385.
  12. ↑ Stahl, W., H. Boigk, and G. Wollanke, 1978, Carbon and nitrogen isotope data of upper Carboniferous and Rotliegend natural gases from north Germany and their relationship to the maturity of the organic source material: Advances in Organic Geochemistry 1976, p. 539–559.
  13. ↑ Jenden, P. D.,and I. R. Kaplan, 1989, Origin of natural gas in Sacramento basin, California: AAPG Bulletin, vol. 73, p. 431–453.
  14. ↑ Parker, C., 1974, Geopressures and secondary porosity in the deep Jurassic of Mississippi: Transactions of the Gulf Coast Association of Geological Societies, vol. 24, p. 69–80.
  15. ↑ Jüntgen, V. H., and J. Karweil, 1966, Gasbildung and gasspeicherung in steinkohlenfluzen, I. gasbildung: Erdöl und Kohle-Erdgas-Petrochemie, vol. 19, p. 339–344.

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