Abstract A diagenetic model based on convective fluid flow has been analyzed for typical reservoir conditions. Calculations based on the model suggest that a significant fraction of the inorganic diagenesis observed in sandstone reservoirs can be attributed to the presence of slowly circulating aqueous fluids. Stability considerations indicate that static pore fluids do not exist in porous bodies of geologic dimensions and that pore fluids will convect at a rate of about 10 −8 m per sec (~1 m per yr) in the presence of a normal geothermal gradient (25° C per km). If it is assumed that the pore fluid maintains chemical equilibrium with the rock matrix, it follows that mass must be transferred as the fluid crosses isotherms. Minerals such as quartz, which have prograde solubilities under normal reservoir conditions, will move from hot source zones to cooler sinks. Minerals such as calcite, which have retrograde solubilities, will move from cool sources to hot sinks. The net effect is a continuous transfer of rock matrix in the reservoir for as long as the fluid circulates. Because the temperature field can change sharply along a streamline, convection can localize precipitation and dissolution zones. In anticlinal structures, the fluid flow is most likely a modified torus in which warm fluid flows up the base of the ascending limb while cooler fluid flows down along the upper surface. The regions of most rapid heating and cooling of the fluid occur at the synclinal troughs and at the anticlinal crests. This flow pattern will produce zones of intense diagenesis at the crests and troughs of the structure. Zones of secondary porosity produced by the dissolution of framework grains or previously deposited cements are also predictable and the model provides explicit conditions for isomorphic replacement. Since hydrocarbon solubilities are similar to quartz solubility in the temperature range 60–150° C, hydrocarbon transfer and accumulation should closely approximate that of quartz. Calculations suggest that convection can transfer significant quantities of hydrocarbons in molecular solution and exsolve them in traps in relatively short geologic times. The convection model thus links inorganic and organic diagenesis and provides reasonable explanations for such observed phenomena as secondary porosity and thermal anomalies.

Abstract The Anadarko basin is one of the most prolific hydrocarbon provinces in North America. Examination of more than 50 cores from the Pennsylvanian Morrow sandstones reveals a complex diagenetic history. Although quartz is the major framework constituent of sandstones, shell fragments, glauconite, and clayey matrix occur in considerable amounts throughout the section. Diagenetic complexity is a function of depositional environment and burial and thermal history of the basin. Most porosity in the Morrow sandstones throughout the Anadarko basin is secondary in origin. Such porosity results from the dissolution of clayey matrix, carbonate fragments and cement, glauconite, and quartz grains and their overgrowth. Evolution of secondary porosity is related to the hydrogen (H + ) ions produced directly from the organic material maturation processes of Morrow shales. Carbon dioxide (C0 2 ) gas, with concentrations ranging from 0.3 to 4.7% by volume, was detected in more than 150 natural gas wells monitored in the basin. Based on geothermal and geopressure gradients and on experimental investigations of the solubility potential of CO 2 in formation fluids under elevated temperatures and pressures, a good estimate of solubility of CO 2 in the Morrow formation water may be attained. Because the concentration of CO 2 appears to increase with depth in the basin, secondary porosity should not be restricted to a particular zone or to particular depths but should persist with depth. Organic acids at shallow depths and H 2 S in deeper zones may be important in secondary porosity enhancement. Amounts of porosity and the geometry of pore space are directly related to the original lithology. A better understanding of lithofacies is critical in evaluating reservoir quality.

ABSTRACT Characterizing unconventional reservoirs involves the investigation of a wide range of potential source-rock targets at various stages of thermal maturity. These samples may contain a mixture of kerogen, bitumen, oil, and pyrobitumen within their fabric. Thus, it is critical that we properly identify and examine each organic phase to better understand reservoir properties. In the present study, we have selected samples of gilsonite from a naturally occurring solid hydrocarbon deposit to serve as an analog for characterizing the bitumen phase of generation. Gilsonite is an aromatic-asphaltic solid bitumen found in vertical veins along the eastern portion of the Uinta Basin, Utah. It is thought to be an early generation product from oil-prone Green River Shale source beds and is similar to low-maturity crude oil in composition. It has a high nitrogen content, low sulfur content, and high melting point (fusibility) and is soluble in organic solvents. We have used a variety of analytic methods to characterize this material, including standard optical organic petrology and scanning electron microscopic imaging to examine the occurrence of organic porosity. Optical organic petrology analyses using both air and oil immersion objectives show that the polished gilsonite surfaces are typically dark grey and featureless. Optical evidence for the presence of macerals and inorganic constituents is absent. Visual estimates suggest that fractures make up approximately 1% of the conchoidal fracture plane, whereas the pencillated variety contains approximately 2% fractures along with 5% shallow pits. Scanning electron microscopic images also show the occurrence of fractures within gilsonite, but the matrix contains no evident organic porosity. The results of our analyses suggest that, unlike pyrobitumen, pre-oil solid bitumen represented by gilsonite was found to contain no significant occurrences of organic nanoporosity within its matrix. Gilsonite does have minor pitting and fractures, but these do not represent an effective interconnected pore network and are probably artifacts of weathering/sampling. Thus, this material would not represent a potential candidate for in-situ petroleum storage capacity. Whether this is typical of all naturally occurring solid bitumen is debatable, considering that gilsonite has undergone some secondary alteration via devolatilization and limited biodegradation. Nevertheless, the pore-scale imaging of this solid bitumen provides potentially important new insights for unconventional reservoir characterization.

Abstract It now is generally accepted that some of the petroleum generated in organic-rich source rocks can move to reservoir rocks and accumulate. Movement of hydrocarbons (or their percursors) through an aqueous medium involves complex interactions among the mobile organic materials, kerogen, rock matrix and water, and all of them change in composition and/or amount with increasing depth of burial. Water is present in large quantities during the early stages of compaction but its availability diminishes with depth unless supplied by the smectite-illite conversion. The average pore size in shales also decreases with depth. The organic material available for migration initially contains high concentrations of compounds with oxygen, nitrogen, and sulfur (which impart enchanced solubility in water). However, as depth increases these become quantitatively less important and increased amounts of hydrocarbons are generated from the kerogen. Shallow oils are relatively rich in nitrogen, sulfur, and oxygen compounds, but with increasing depth these give way to more mature oils, then condensates, and finally to dry gas. Thus, the nature of the material migrating changes with depth as do the rock and water system through which it moves, and it seems very likely that there is not one mechanism of migration, but many, and that for different conditions different mechanisms will operate. Mechanisms involving transport of hydrocarbons, precursors, or micelles in water require some process to cause exsolution. Because the biggest discontinuities in chemical and physical properties are at the sand- shale contact this seems to be the most likely place for exsolution. Where sufficient hydrocarbons are generated in the source rock a separate oil phase separates, and if the water is structured close to clay surfaces the hydrocarbons will accumulate in the centers of the pores, ultimately forming a pore center network. This will be squeezed as the water expands thermally and droplets will be expressed from the ends of the network. This mechanism operates even where the network is discontinuous. Comparison of crude oil composition with the source rock extract shows that in general saturate materials move in preference to the aro- matics, with the NSOs being least mobile. This is the reverse of the solubility trend but is the sequence of adsorption. It appears that adsorption of bitumens in the source rock has an important influence on the composition of the material that migrates. The various migration mechanisms probably all operate to some extent, with one or more being dominant under any set of geologic conditions.

Abstract It is now generally accepted that some of the petroluem generated in organic-rich source rocks can move to reservoir rocks and accumulate. Movement of hydrocarbons (or their percursors) through an aqueous medium involves complex interactions among the mobile organic materials, kerogen, rock matrix and water, and all of them change in composition and/or amount with increasing depth of burial. Water is present in large quantities during the early stages of compaction but its availability diminishes with depth unless supplied by the smectite-illite conversion. The average pore size in shales also decreases with depth. The organic material available for migration initially contains high concentrations of compounds with oxygen, nitrogen and sulfur (which impart enhanced solubility in water). However, as depth increases these become quantitatively less important and increased amounts of hydrocarbons are generated from the kerogen. Shallow oils are relatively rich in nitrogen, sulfur and oxygen compounds but with increasing depth these give way to more mature oils, then condensates and finally to dry gas. Thus, the nature of the material migrating changes with depth as do the rock and water system through which it moves, and it seems very likely that there is not one mechanism of migration, but many, and that for different conditions different mechanisms will operate. Mechanisms involving transport of hydrocarbons, precursors or micelles in water require some process to cause exsolution. Since the biggest discontinuities in chemical and physical properties are at the sand-shale contact this seems to be the most likely place for exsolution. When sufficient hydrocarbons are generated in the source rock a separate oil phase separates and if the water is structured close to clay surfaces the hydrocarbons will accumulate in the centers of the pores, ultimately forming a pore center network. This will be squeezed as the water expands thermally and droplets will be expressed from the ends of the network. This mechanism operates even when the network is discontinuous. Comparison of crude oil composition with the source rock extract shows that in general saturate materials move in preference to the aromatics, with the NSO's being least mobile. This is the reverse of the solubility trend but is the sequence of adsorption. It appears that adsorption of bitumens in the source rock has an important influence on the composition of the material that migrates. The various migration mechanisms probably all operate to some extent, with one or more being dominant under any particular set of geologic conditions.