Paul D. Lundegard

Problem of secondary porosity: Frio Formation (Oligocene), Texas Gulf Coast

Secondary porosity, formed by the dissolution of both carbonate and silicate minerals, especially K-feldspars, is widely developed in sandstones of the Frio Formation (Oligocene) in the Texas Gulf Coast. CO 2 produced by decarboxylation of organic matter is commonly suggested as the acid required for dissolution. Material balance calculations indicate that CO 2 produced by decarboxylation of organic matter in Frio Formation shales can account for a regional average of only 1% or 2% secondary porosity in Frio Formation sandstones, yet point-count data indicate an average of 10% secondary porosity. Long-distance fluid transport (many kilometres) and/or other mechanisms of acid generation should, therefore, be considered. Carbon isotopic data on dissolved inorganic carbon in formation water, CO 2 in produced natural gas, and carbonate cements indicate that CO 2 produced by decarboxylation had a minor impact on these carbon reservoirs. The reaction kerogen + water → methane + carbon dioxide can explain the isotopic data, but alone it is insufficient to account for all the secondary porosity unless long-distance material transport is involved.

Carbonate equilibria and pH buffering by organic acids — Response to changes in pCO2☆

Abstract Organic acid anions such as acetate (a natural product of the thermal breakdown of kerogen) may buffer the pH of natural formation waters. The extent of pH buffering by acetate should determine whether an increase in the partial pressure of carbon dioxide ( p CO 2 ) will lead to calcite dissolution (porosity enhancement) or calcite precipitation (porosity destruction). Successful prediction of porosity therefore requires a quantitative understanding of this process. This paper presents computer simulations of the response of the acetic acid-carbonate system to changes in p CO 2 for typical reservoir fluid compositions and temperatures. The effects of variations in temperature, ionic strength, initial Ca 2+ concentration, and the magnitude of the change in p CO 2 were investigated. Natural formation waters from Cenozoic reservoirs in the Gulf Coast Basin and California show maximum organic acid concentrations at 100 ± 20°C. At 100°C, the simulations show that for concentrations of acetic acid up to ∼0.06 m (3600 mg l −1 ), increases in the p CO 2 of initially calcite saturated solutions will promote calcite undersaturation. At higher temperatures, equivalent buffering responses occur at lower acetic acid concentrations but acetic acid concentrations in natural formation waters also decrease rapidly with increasing temperature. Since present-day concentrations of acetic acid in formation waters from Cenozoic reservoirs rarely exceed 0.06 m , increases in p CO 2 will generally promote calcite dissolution by these waters. In the Gulf Coast Basin, variation in organic acid concentrations as a function of reservoir age suggests that reductions in dissolved organic acid concentrations over geologic time have been relatively small. It can be concluded, therefore, that at any point in the histories of these reservoirs, an increase in p CO 2 would have promoted calcite dissolution, despite the effects of pH buffering by acetate. Since increases in p CO 2 will in most Cenozoic basins promote calcite dissolution, knowledge of the location and timing of CO 2 production in the subsurface can more easily be applied to the prediction of calcite cementation and dissolution.

Timing of hydrocarbon generation and accumulation in fault-bounded compartments in the Norphlet Formation, offshore Alabama

Abstract Analysis of the variation in depth of the gas-water contacts in the Bon Secour Bay and Lower Mobile Bay-Mary Ann Fields of offshore Mobile Bay, Alabama, together with fault seal analysis, implies that some of the pre-Cretaceous faults in these fields must be sealing. It is also likely that the large, post-Cretaceous Lower Mobile Bay Fault is dip-leaking. The gas currently reservoired in the Norphlet Formation has most likely been produced by thermal degradation of oils generated in the overlying Jurassic lower Smackover Formation. For a range of heat flow models appropriate for this area of the Gulf Coast, the onset of gas generation (defined as the time at which 10% of the maximum possible amount of gas has been generated) occurs at 104 −5 +10 Ma. The error bounds in this estimate are the 90% confidence limits, which were calculated by assuming that the times of onset of gas generation are log-normally distributed. The time of onset of gas generation is younger than the age of the sealing faults in the area, hence it is likely that gas generation occurred in situ in the Norphlet Formation, with re-migration occurring during the development of the post-Cretaceous Lower Mobile Bay Fault.