Source rocks history

Shackleton N. J. (1987) The carbon isotope record of the Cenozoic history of organic carbon burial and of oxygen in the ocean and atmosphere. In Marine Petroleum Source Rocks Geological Society Special Publication 26 (eds. J. Brooks and A. J. Fleet). Blackwell, Boston, pp. 423-434. 

CarroU, R. R, Pashin, J. C., and Kugler, R. L, 1995, Burial history and source-rock characteristics of Upper Devonian through Pennsylvanian strata. Black Warrior basin, Alabama Geological Survey of Alabama Circular, v. 187, p. 29. 

At North Coles Levee, carbon isotope values fluctuate between zero and -12%o in cements estimated to have formed at intermediate burial depths between 4 and 5 Ma (Wood Boles, 1991). These fluctuations are interpreted as being the result of pulses of fluid from deep basin levels mixing with local fluids (Wood Boles, 1991). Burial history reconstruction for the basin indicates that shale source rocks, such as the Eocene Kreyenhagen, would have been at an appropriate depth to be a CO2 source (Fig. 3). 

Parnell, J. (1992) Burial histories and hydrocarbon source rocks on the North West Seaboard. In Basins on the Atlantic Seaboard Petroleum Geology, Sedimentology and Basin Evolution (Ed. Parnell, J.). Spec. Publ. Geol. Soc. London, 62, 3-16. 

Wojcik, K.M., McKibben, M.E, Goldstein, R.H. Walton, A.W. (1992) Diagenesis, thermal history, and fluid migration. Middle and Upper Pennsylvanian rocks, southeastern Kansas. In Source Rocks in the Southern Midcontinent, 1990 Symposium, Norman/OK (Eds Johnson, K.S. Cardott, B.J.). Oklahoma Geol. Surv. Circ., 93, 144-159. 

The model simulates the history of shaly source rock for an assumed burial and thermal history. The results discussed here are based on a constant sedimentation rate of 500 m/m.y., and a geothermal gradient of either 30 C/km or60 C/km, A Gulf Coast-type porosity gradient for shale is used, where porosity = 0.39 depth (ft) increment... 

Spatial fluid density variations are frequently inherited from the filling history of the reservoir. The initial fluids expelled from a source rock are relatively dense liquids. As a source rock becomes more thermally mature, it expels progressively lighter fluids and eventually gases. When such fluids fill a reservoir, and fill and spill from compartment to compartment within a reservoir, each part of the reservoir can end up with different proportions of fluids of different maturity and density. Field observations show that the segment of the reservoir closest to the source kitchen has often received the latest, lowest density charge. Those areas farthest away from the source kitchen may contain earlier denser fluids that have filled and spilled to their current location. 

Furthermore, the undersaturated nature of the petroleum is suggested not to be primarily controlled by the maturity of the source rock, but rather by the cap rock properties (Sales 1997) and the burial (pressure) history of the accumulation. The same mechanism is suggested to cause more shallow fields in the area to maintain a black oil preference as lower boiling compounds are rapidly leaking from the relatively poor seals. 

Indeed all our evidence from studying the filling histories of fields (cf. Karlsen Larter 1989, 1991 Horstad et al. 1990 Karlsen et al. 1993, 1995 Skalnes 1993 Skalnes et al. 1993 Horstad 1995 Larter Aplin 1995 Angard 1996 Steinhoff 1996 Bhullar et al. 1998, 1999a,b Sletten 2003 Winterstad 2003 Xu 2003) indicate that structures which in the distant past (e.g. 70-50 Ma bp), were linked to establish oil wetting migration systems, will continue to utilize reservoir-proximal parts of this system even when other more shallowly buried source rocks become mature. 

Formation waters are often very saline, often containing more than 200 000 ppm total dissolved solids (Ryder et al. 1996). In addition, the in-situ connate water is most often present as an irreducible (non-mobile) water phase (Law 1984a,b, 1985 Ryder et al. 1996). The hydrocarbon properties vary depending on the type of BCGS, the source rock characteristics, and the effects of burial history on temperature and pressure gradients. 

Source rock maturity. In a study of the diagenesis and burial history of the Lower Cretaceous Travis Peak Formation in eastern Texas, Dutton (1987) reported measured vitrinite reflectance values for Travis Peak shales generally ranged from 1.0 to 1.2%. Westcott Hood... 

Geochemical Characterization of Potential Source Rocks, Hydrocarbons and Burial Histories... 

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