Biodegradation of Crude Oils in Reservoirs

Much of the world's oil and gas has been generated from source rocks inside deep (> 3,000 m or 9,840 ft) seal-bounded fluid compartments. The quantity and composition of the kerogen and the burial history of the source rocks determine the volumes of petroleum generated; however, the migration from the compartments in an oil and gas phase is a pressure-driven process in which the flow direction is controlled by the configuration and internal pressures of the fluid compartments. Many sedimentary basins contain layers of two or more superimposed hydrogeological systems. The shallow systems are usually basin wide in extent and exhibit normal hydrostatic pressures. The deeper systems, where the oil is generated, are not basin wide and are abnormally over pressured. They usu lly consist of a series of individual fluid compartments that are not in hydraulic pressure communication with each other nor with the overlying hydrodynamic regime. Tops of fluid compartments in currently sinking basins do not always follow a specific stratigraphic horizon. They frequently have planar tops and subsurface temperatures ranging from 90 degrees to 100 degrees C (194 degrees to 212 degrees F). The tops in clastic sediments appear to be caused by carbonate mineralization along a thermocline. In the North Sea, the depth to the top of the deepest seal changes with the geothermal gradient. The seal is deeper where the gradient is lower. The generation of oil and gas within the compartments plus the thermal expansion of pore fluids eventually causes fracturing of the top compartment seal during periods of basin sinking. Hydrocarbons and other pore fluids then move vertically into the overlying lower pressured sediments and accumulate in the nearest structural and stratigraphic traps. Seal fracturing causes a pressure drop with compartment fluids rushing to the breakout point. The compartment then re-seals and pressure builds to another breakout. This episodic process continues with resealing and breakout cycles probably occurring in intervals of thousands of years in rapidly sinking basins such as the United States Gulf Coast. This concept of episodic dewatering of deep-basin fluid compartments needs to be considered n any basin-modeling program where the bulk of the oil generation occurs in the compartmented overpressured section of the basin and the oil moves vertically into the normally pressured rocks above.

Generation and Migration of Petroleum from Abnormally Pressured Fluid Compartments: Reply

Crude oils from Venezuela, Oklahoma, and New Mexico were water washed in the laboratory at temperatures from room temperature to 80°C, and with water salinities from 0 to 300,000 mg/L in experiments lasting from 7 to 338 hours. The effects of water washing were determined by gas chromatographic and gas chromatography-mass spectrometric analysis of the residual oil. These experiments show that water washing is particularly effective for the C15- fraction and hydrocarbons are removed in the sequence aromatics, then n-alkanes, then naphthenes. In the C15+ fraction, no loss of pristane, phytane, steranes, or terpanes occurs, but some aromatics and sulfur compounds, especially dibenzothiophene, are depleted. Although water washing reduces API gravity water washing is unlikely to produce tar layers. The effects of water washing were simulated with a numerical model based on the equation of diffusion. Predicted oil-water ratios were in good agreement with the experimental values for the light ends, and the model suggests that water washing is very fast in the subsurface. Comparison of oils that appeared to have been water washed in nature with the equivalent unwashed oils showed the expected compositional trends. Water washing is probably the dominant process affecting crude oil composition in the subsurface when water flows past oils under conditions where bacterial degradation is precluded by temperature (> 80°C) or by lack of dissolved oxygen, and the temperatures are too low for thermal cracking.

Effect of Water Washing on Crude Oil Compositions

Petroleum consists of an exceedingly complex mixture of hydrocarbons and non-hydrocarbons, extending from methane to macromolecular aggregates. The relative proportions of these components are quite variable and depend initially on the nature of the kerogen in the parent source rock and its level of maturity at the time of expulsion, and subsequently upon the pressure and temperature conditions of the source-carrier-reservoir system during expulsion, migration and accumulation. Under subsurface reservoir conditions the petroleum may be in a single vapour phase, in which case it is termed a gas accumulation, a single liquid phase, as exemplified by crude oils which are undersaturated with respect to gas, or a two-phase system comprised of a gas cap in equilibrium with an underlying crude oil accumulation. When produced at the surface, the petroleum changes from its sub-surface state as gaseous and liquid components segregate. For instance, the C1-C4 components that are dissolved in undersaturated petroleums under sub-surface conditions exsolve to give gas, while the major remaining liquid portion shrinks in volume and is termed crude oil. Similarly, as natural gases are produced dissolved C5+ components condense out as liquids or solids, giving rise to “condensate”.

The Bulk Composition of First-Formed Petroleum in Source Rocks

Hydrocarbon-water interactions during brine migration: Evidence from hydrocarbon inclusions in calcite cements from Danish North Sea oil fields

Geochemical studies provide important data relevant to the origin of the oils in the Santa Cruz basin, Bolivia. Production from this basin occurs from rocks of Devonian, Carboniferous, Cretaceous, and Tertiary ages. The productive structures are usually undisturbed by major faulting. The Devonian sediments are composed of sandstones and dark marine shales. The post-Devonian rocks are generally oxidized and probably nonmarine. The Tertiary and Cretaceous reservoirs usually contain the highest API° gravity oils. Comparison of geochemical data (N5-N10 molecular weight range) shows that the oils are very similar; however, systematic compositional trends occur as a function of API° gravity. These trends are interpreted from gross structural group data. Isoparaffins and cycloparaffins increase in relative abundance, while normal paraffins and aromatics decrease with increasing API° gravity. A model is proposed that rationalizes these compositional trends by a mechanism of "accommodation" in water. The model requires enrichment of hydrocarbons of intermediate solubility, partial exclusion of hydrocarbons of low solubility, and retention in solution of the more soluble hydrocarbons. Processes such as thermal fractionation and biodegradation fail to account satisfacto ily for the observed compositional trends. The compositional interrelationships of the oils coupled with the geologic framework suggest that these oils have a common source, most probably the Devonian. Differences between the oils are attributed to fractionation occurring during migration. Exploration risk for areas such as the Santa Cruz basin can be substantially reduced by use of the knowledge derived from petroleum geochemistry.

Geochemistry of Oil from Santa Cruz Basin, Bolivia: Case Study of Migration-Fractionation

Fifteen oils from the Maranon basin, Peru, were chemically analyzed to ascertain possible genetic interrelations. Correlation of the oils was achieved by use of normal paraffin and isoprenoid-type hydrocarbon compositions. The oils were analyzed using the whole oil as received from the field. Two major oil types were observed--one containing abundant normal paraffins, the other minor normal paraffins (naphthenic). Using isoprenoid ratios, it was concluded that the two major oil types most probably are cogenetic with respect to source chemistry. The observed compositional differences are interpreted to be independent of source control. The paraffinic type 1 oils are interpreted to represent most closely the parent composition. The naphthenic type 2 oils are interpreted to e degradation products of type 1 oils.

F. R. Haney

Papers

Geochemistry of Oil from Santa Cruz Basin, Bolivia: Case Study of Migration-Fractionation

Hydrocarbon Geochemistry of Oils from Maranon Basin, Peru