E. Sven Hagen

Organic-Inorganic Interactions and Sandstone Diagenesis

The maturation of organic material in hydrocarbon source rocks and inorganic diagenetic reactions in reservoir sandstones are a natural consequence when a prism of sedimentary rocks is buried. We can predict the distribution of porosity and permeability enhancement in potential hydrocarbon reservoirs by integrating the reaction processes characterizing the progressive diagenesis of a reservoir/source rock system. A variety of observations suggests that the organic solvents needed to increase aluminosilicate and carbonate solubilities in sandstones can be generated either by thermal or oxidative cracking of carbonylic or phenolic groups from kerogen in adjacent source rocks. For example, nuclear magnetic resonance (NMR) spectra of kerogen show that peripheral carbonylic and phenolic groups are released from the kerogen molecule before liquid hydrocarbons are generated. Experimental data indicate these water-soluble organic species can significantly affect the stability of both carbonates and aluminosilicates. Water-soluble organic acid anions (carboxylic) have been observed in oil-field waters in concentrations up to 10,000 ppm, and they commonly dominate the alkalinity in the fluid phase from 80° to 120°C. We can model the integration of organic and inorganic diagenetic reactions by constructing a series of potential reaction pathways with increasing temperature for a system that includes aluminosilicates, carbonates, organic chelate species (carboxylic and phenolic), and CO2. The important chemical divides in these diagenetic flow diagrams are dependent on temperature, the nature of the pH buffer (carbonate species or organic acid anion species), and the relationship between organic acid anions and PCO2 (P = partial pressure). Forward predictive capabilities result when this general diagenetic model is placed in a time-temperature framework. The detailed organic and inorganic geochemistry and the general thermal scenario used in the time-temperature ana ysis must be basin specific. Casting the diagenetic history of a sandstone into this type of process-oriented model helps us move from a descriptive mode to a predictive mode of analysis. Two types of information result: (1) general optimum conditions for porosity and permeability enhancement in sandstones are delineated and (2) specifically, the degree and potential for porosity and permeability enhancement are determined. Predictive models have been developed for several tectonic settings, including rift or pull-apart basins and intermontane or Laramide basins. From these reconstructions, we can forward-predict the porosity-enhancing potential of a diagenetic system based on an understanding of the reaction process in a time-temperature framework.

Tectonic loading and subsidence of intermontane basins: Wyoming foreland province

Results of two-dimensional flexural modeling of the northern Bighorn and northern Green River basins in the Wyoming foreland province suggest that these basins formed as flexures in response to loading by basin-margin uplifts and basin sedimentary sequences. The northern Bighorn Basin subsided due to loading by the Beartooth uplift along its western margin. The northern Green River Basin developed as a result of concurrent loading by the Wyoming thrust belt to the west and the Wind River uplift to the east. Tectonic loading from basement-involved uplifts played a major role in subsidence and sedimentation, as evidenced by isopach patterns within each basin. Lithospheric flexural rigidities of 1021 to 1022 newton metres (N·m) can adequately explain subsidence in both basins.

Maturation History and Thermal Evolution of Cretaceous Source Rocks of Bighorn Basin, Wyoming and Montana: ABSTRACT

The Laramide basins of the Rocky Mountain region are deep asymmetric structural depressions containing thick sequences of Upper Cretaceous and Tertiary sandstone strata. The combined effects of tectonics and sedimentation have contributed to the thermal evolution of the basins and to the maturation history of the source rocks. In the Bighorn basin of Wyoming and Montana, total organic carbon (TOC) values for samples from a 2,000-ft (610-m) thick interval, including the Thermopolis, Mowry, Frontier, and Cody Formations, average 1 wt. %. The hydrogen indices and elemental analyses suggest that most of the samples presently contain kerogen between types II and III. The genetic potential of these samples suggests that they are moderately good source rocks. Vitrinite reflectan e values, production indices, elemental analyses, and the distribution of extractable hydrocarbons suggest that these Cretaceous source rocks can be within the liquid hydrocarbon window from a present day depth of 2,000-3,000 ft (610-914 m) down to 11,000-12,000 ft (3,353-3,658 m). On the basis of these observations, plus graphical and numerical thermal models for the Bighorn basin, it is suggested that (1) the Cretaceous section has generated hydrocarbons and could have produced the hydrocarbon production in the Bighorn basin, particularly from Cretaceous reservoirs, (2) migration distances for hydrocarbons into Cretaceous reservoirs could be short, (3) the stratigraphic and lateral distribution of marine sandstones intercalated within the Cretaceous source rocks provide ample opportunity for stratigraphic and/or diagenetic traps over a wide depth interval in this basin, and (4) owing to variations in thermal gradients within this basin, or similar Laramide-type basins, the hydrocarbon liquid window is expanded over a particular stratigraphic interval with dept . End_of_Article - Last_Page 937------------

Thermal Evolution of Laramide-Style Basins: Constraints from the Northern Bighorn Basin, Wyoming and Montana

The Laramide-style basins of the central Rocky Mountain region are deep asymmetric structural depressions containing thick sequences of Upper Cretaceous and Tertiary strata. The combined effects of tectonics and sedimentation have contributed to the thermal evolution of the basins and to the maturation history of Cretaceous hydrocarbon source rocks.

Hydrocarbon Maturation in Laramide Basins--Constraints from Evolution of Northern Big Horn Basin, Wyoming and Montana: ABSTRACT

Thermal and mechanical models were used to quantify the effects of Laramide uplifts and subsequent synorogenic deposition on the hydrocarbon maturation of Cretaceous source rocks in the Big Horn basin. Laramide deformation and resultant sedimentation has clearly affected hydrocarbon maturation of Cretaceous source rocks (Thermopolis, Mowry, Frontier, Cody). Modified Lopatin-type reconstructions suggest that a significant region containing Cretaceous source rocks has been within the liquid hydrocarbon window. The earliest onset of hydrocarbon maturation in the northern Big Horn basin was latest Eocene, with some regions still containing immature Cretaceous source rocks as a consequence of Cenozoic erosion, uplift of the Pryor Mountains, and lack of burial. Regional geologic features indicate that the basin formed as a result of flexural compensation of an elastic lithosphere during emplacement of the Beartooth and Pryor Mountains, and possibly the Absaroka volcanics. This was determined by 2-dimensional models which predict sediment thicknesses caused by tectonic loading and subsequent sedimentation. Flexural rigidities of 1021-1022 newton-meters adequately explain flexural subsidence in the northern Big Horn basin. The present basin configuration also was compared with a theoretical profile based on geologic constraints. Subsidence models for the present basin profile suggest that Paleocene thrusting of the Beartooth block contributes a majority of the tectonic loading and that Cenozoic erosion has drastically affected the resultant sedimentary sequence (Fort Union and Wasatch). These models, along with stratigraphic reconstructions, can be combined to pinpoint areas of potential hydrocarbon maturation within Laramide-type basins. End_of_Article - Last_Page 482------------