Abstract Acoustic impedance contrast “dim spots” (previously described as the “fuzzy effect” in Maucione, 1993) have been associated with anomalously pressured hydrocarbon accumulations in the Powder River Basin of Wyoming (Boyd et al., 1996a, b). It is important to know if the observations made in the Powder River Basin apply to anomalously pressured hydrocarbon accumulations in other Rocky Mountain Laramide basins. In order to test the applicability of these conceptsin anotherbasin, a ~58 km (36 mi) long seismic profilefrom the AlbertaDeep Basin of western Canada has been constructed and analyzed. The profile crosses various pressure boundaries, but the reservoir geometry and seismic acquisition and processing parameters remain nearly constant throughout the length of the profile. These parameters may thus be eliminated as causes of seismic anomalies that could falsely indicate anomalous pressures. Anomalous pressures in the Alberta Deep Basin were originally identified using well log and production information. However, using seismic data acquired and processed to detect character response changes other than those associated with structural features, one can easily observe deviation from the expected increase in velocity with depth. Understanding the exact character of anomalous seismic responses requires knowledge of some geo–logic data, including rock properties (e.g., lithology and velocity) and depo–sitional environments present in a similar geologic setting (i.e., another Laramide basin). Additionally, integration of well log and production infor–mation corroborates the seismic character response changes associated with a regional–scale pressure boundary. However, it is important to note that identification of areas of anomalous pressure using seismic data is not dependent on well information. In the present study, four seismic response characteristics of the seismic data from the Alberta Deep Basin indicated that a regional–scale pressure compartment boundary, separating areas of normal and anomalous pressure, was present in the basin. Two of these characteristics can be observed in a routine processing flow. The other two characteristics can be observed only after an extremely detailed velocity analysis.

Abstract A significant portion of the Cretaceous shales in the Rocky Mountain Laramide Basins (RMLB) are overpressured on a basinwide scale. The change of pressure regime from normally pressured to overpressured coincides with marked changes in the geochemical and geophysical properties of the Cretaceous rock/fluid system. Sandstone bodies within the overpressured shale section are subdivided stratigraphically and diagenetically into relatively small, isolated, gas-saturated, anomalously pressured compart-ments. The driving mechanism of the pressure compartmentalization is the generation and storage of liquid hydrocarbons that subsequently react to gas, converting the fluid-flow system to a multiphase regime in which capillarity controls permeability. A new exploration paradigm and an exploitation strategy have been created that significantly reduce exploration risk in the RMLB. Two elements crucial to the development of prospects in the deep, gas-saturated portions of the RMLB are (1) the determination and, if possible, three-dimensional eval-uation of the pressure boundary between normal and anomalous pressure regimes and (2) the detection and delineation of porosity/permeability “sweet spots” (i.e., areas of enhanced storage capacity and deliverability) in potential reservoir targets below this boundary Certainly there are other critical aspects, but completion of these two tasks is essential to the successful exploration for the unconventional gas resources present in anomalously pressured rock/fluid systems in the RMLB.

Abstract Predicted cation ratio geothermometry temperatures, using equations of Na-K, Na-K-Ca, Mg-Na-K-Ca and Mg-Li, were compared between oilfield and geothermal settings. Geothermometers in oilfield waters yielded less consistent temperature predictions compared to geothermal waters in the same temperature range. Scatter of predicted temperature in oilfield waters is greatest in the temperature interval where carboxylic acid anions (CAAs) are in greatest concentration. CAAs are not present in geothermal systems. Temperature prediction improves in those oilfield waters where CAAs are present and account for less than 80% of total alkalinity. The assumptions of cation ratio geothermometry are violated to varying degrees in oilfield waters where CAAs are abundant. These assumptions are: (1) cation ratios are controlled by exchange between solid aluminosilicates. However, CAAs affect mineral solubility by forming complexes with the cations. Therefore. the ratios of cations in solution differ from those values expected when cation exchange between aluminosilicate minerais is the only control on the cation ratios. Furthermore, concentrations of Ca and Mg are strongly controlled by carbonate equilibria, which in turn is strongly affected by the presence of CAAs; (2) aluminum is conserved in solid phases. However, CAAs form stable complexes with Al, increasing Al-silicate solubility and mobilizing Al; thus Al may not be conserved m mineral phases; (3) neither H 1 nor CO, enter into the net reactions (i.e., pH is buffered by aluminosilicate hydrolysis). However, acetate (the dominant CAA found in oilfield waters) is an effective buffer of pH in feldspathic rocks. Also, at higher temperatures, decarboxylation of CAAs increases the P C02 of oilfield waters. The consistently worse temperature prediction of cation ratio geothermometers in oilfield waters in the 80-120°C temperature range is another indication that organic-inorganic diagenesis is an important control on oilfield water chemistry.

Abstract The Cretaceous shale section in the Powder River basin below a present-day depth of approximately 8000 ± 2000 ft (2400 ± 600 m) typically is over-pressured. The top of the transition zone, 500-1000 ft (150-300 m) thick, in the upper portion of the overpressured section occurs within the Steele Formation; and the “hard” overpressured zone, ~2000 ft (600 m) thick, typically begins in the Niobrara Formation, with the base of the zone parallel to the Fuson Shale, the lowermost organic-rich shale in the Cretaceous stratigraphic section. The upper and lower boundaries of the pressure compartment are subparallel to stratigraphic boundaries. Toward the basin margin where the Cretaceous section is at shallow depth (~6000 ft [1800 m]) the overpressured shale section is wedge shaped. The overpressured Cretaceous shale section in the Powder River basin is a basinwide dynamic pressure compartment. The driving mechanism is the generation of liquid hydrocarbons that subsequently partially react to gas, converting the fluid-flow system to a multiphase regime where capillarity dominates the relative permeability, creating elevated displacement pressures within the shales. In contrast, many of the Cretaceous sandstones are subdivided into relatively small, isolated pressure or fluid-flow compartments 1 to 10 mi (1.6-16 km) in greatest dimension. The compartmentation is the result of internal stratigraphic elements, such as paleosols along unconformities. These internal stratigraphic elements are low-permeability rocks with finite leak rates in a single-phase fluid-flow system but evolve into relatively impermeable capillary seals with discrete displacement pressures as the flow regime evolves into a multiphase fluid-flow system. This evolution of the fluid-flow system is caused by the addition of hydrocarbons to the fluid phase as a result of continuous burial and increasing thermal exposure. The three-dimensional closure of the capillary seals above, below, and within a sandstone results in isolated fluid-flow or pressure compartments within the sandstone. Not all the sandstones within the overpressured shale section are at the same pressure as the shales; some are overpressured, some are normally pressured, and some even appear to be underpressured. Those sandstones characterized by compartmentation (three-dimensional closure of capillary seals) are above, at, or slightly below the pressure of the adjacent shales. The sandstones characterized by normal pressure within the overpressured shale section probably represent fluid conduits connecting with the overlying (at 8000 to 9000 ft [2400-2700 m]) or underlying (below Fuson shale) normally pressured fluid-flow regimes. The major difference between pressure compartmentation in these Cretaceous sandstones and shales is one of scale. In both cases the appearance of hydrocarbons drives the transition from single-phase (water) to multiphase fluid flow (water plus one or more hydrocarbon phases); when the hydrocarbons activate capillary seals, the result is grossly increased displacement pressure. When hydrocarbons saturate the compartment, the integrity of the three-dimensional boundary capillary seals is ensured, and free water is expelled from the system. In summary, understanding the concept of multiphase fluid flow as it relates to three-dimensional pressure compartmentation will greatly expedite the search for, the discovery of, and the exploitation of new unconventional gas resources

Abstract Drill-stem test (DST) pressures from oil and gas wells were analyzed in an attempt to determine the existence of pressure compartments in the Powder River basin. DST data for the entire basin were first sorted by geologic unit for the Mesaverde Formation (984 data values), Sussex Formation (1041 data values), Frontier Formation (821 data values), Muddy Formation (3888 data values), Dakota Formation (1157 data values), and Minnelusa Formation (4470 data values). Initial and final shut-in pressures (ISIP and FSIP) were graphed versus each other and versus depth and elevation to display functional relationships. Potentiometric surfaces were then constructed using the maximum of the ISIP and FSIP. The pressure-elevation plots and potentiometric surfaces clearly show the existence of anomalously pressured zones in the Frontier, Muddy, and Dakota formations. The anomalously pressured zones as determined from the potentiometric surfaces are discrete areas on the scale of individual oil fields. The boundaries of the anomalously pressured areas as shown on the potentiometric surfaces are characterized by steep hydraulic head gradients of up to 12,000 ft (3600 m) of head difference across small horizontal distances of less than 1 mile. These gradients are interpreted as discontinuities in the fluid-flow regime of the Powder River basin. The internal shape of the anomalies is difficult to determine because data are sparse. However, piece-wise continuous least-squares analyses indicate that many of the anomalies contain a nearly horizontal internal potentiometric surface. Given the discontinuous nature of the constructed potentiometric surfaces and the shape of the pressure anomalies, we conclude that oil-field-size pressure compartments exist in the Powder River basin in the Frontier, Muddy, and Dakota formations.

Abstract Sandstones in the Rozet unconformity zone in the Muddy Sandstone are characterized by abundant clay matrix (up to 55% of the rock volume), absence of intergranular pores, and very low permeability. The diagenesis of clay minerals in the Rozet unconformity sandstone and overlying Mowry Shale includes smectite altering to illite in mixed-layer smectite / illite clays (I/S) and kaolinite reacting to chlorite. The I/S composition changes with progressive burial from approximately 20% illite in the mixed-layer smectite/illite clays at 900 m (3000 ft) to 85% illite at 4200 m (13,500 ft). High-pressure mercury injection tests were performed on the sandstone samples from the Rozet unconformity zone. Pore throats for those samples are primarily in the subnano and nano categories (<0.01 to 0.05 μm), and permeabilities are from 0.02 to 0.08 md. Such sandstones can hold a differential pressure of 1800 psi, which is the same as the differential pressure in the Amos Draw overpressured compartment from which the samples were taken. There is a direct correlation between the diagenesis of clay minerals in the Rozet unconformity zone and the maturation of the Mowry Shale, and the sealing capacity or displacement pressure of the pedogenic units. The sealing capacity of the sandstone associated with the unconformity is derived from primary pedogenic processes and from diagenetic enhancement during progressive burial. The diagenetic processes can increase the sealing capacity of sandstone along the unconformity by an order of magnitude, or from a type C seal to a type A seal. The transition of the fluid-flow system from single phase to multiphase results in converting the low-permeability rocks along the unconformity to fluid/pressure seals capable of withstanding >1800 psi pressure differentials. The recognition of the presence of widespread subaerial unconformities in the Muddy Sandstone is important in understanding abnormally-pressured compartments within the reservoir facies.

Abstract Pressure compartment seals all have permeability to single-phase flow. Complete sealing can occur only in a multiphase fluid environment. For physical properties typical of the Powder River basin, Wyoming, Darcy flow allows single-phase leak rates such that observed pressure compartments would leak off in about 1 million years. Pressure compartments can be held indefinitely, however, under multiphase flow. Muddy sandstones of anomalously high threshold displacement pressure, about 2000 psi, appear to contain gas reservoirs at high pressure. Such high displacement pressures correlate well with those of classic carbonate and shale seals. The Muddy, however, contains sandstones capable of sealing adjacent reservoir sandstones. Sealing sandstones correlate with zones of unconformities between sandstones of good reservoir quality. Capillary sealing, as observed here, is certainly a worldwide phenomenon but is not the only mechanism of holding a pressure compartment. Other pressure compartments might be actively leaking (e.g., Gulf Coast type) and geologically temporary. Conversely, the capillary seal is permanent up to the threshold displacement pressure, which is the observed pressure in Muddy pressure compartments.

Abstract In the Powder River basin, pressure compartmentation has been linked to the establishment of multiphase fluid-flow systems. The transition from a single-phase to a multiphase fluid-flow system is driven by liquid hydrocarbongeneration and its subsequent reaction to gas. As a consequence, pressure compartments in this basin should be related to changes in formation water chemistry, thermal maturation of organics, clay diagenesis, and other geochemical reactions associated with progressive burial. To test this, measured and calculated pressure anomalies were studied in relation to changes in formation water chemistry, clay mineralogy, kerogen structure, carbon aromaticity, vitrinite reflectance, and organic-matter production indices. The results indicate that fundamental changes in formation water chemistry, rock inorganic geochemistry, and organic geochemistry occur between about 8000 and 10,000 ft (2400 and 3000 m) present-day burial depth, coincident with a major change in the formation pressure regime, the onset of abnormal pressure, in the Muddy Sandstone. The results also indicate that the onset of abnormal pressure is coincident with the generation, migration, and reaction to gas of liquid hydrocarbons. Thermal modeling, organic geochemistry, and pressure measurements suggest that abnormal pressures have existed in the Muddy and Mowry formations for a geologically significant time (>40 m.y.). Further, geochemical modeling suggests that the rupture of boundary seals accompanied by fluid migration—formation water mixing, temperature drop, and pressure drop—or degassing can cause calcite precipitation and, consequently, seal restoration. These results differentiate the type of pressure anomalies seen in the Muddy Sandstone from those resulting from either compaction or hydrodynamic disequilibria.

Abstract During the past 10 years, much of the research in clastic diagenesis has focused primarily on the recognition and description of porosity modification. Current research efforts emphasize the development of predictive models for porosity enhancement. In order to be truly predictive, the models must be process-oriented. The research that will be presented is part of an ongoing project in the Geology Department of the University of Wyoming to assess the role of source rock maturation in clastic diagenesis. Specifically, the link between organic acids and porosity enhancement will be examined. Enhanced porosity constitutes a significant if not major portion of effective porosity in many hydrocarbon reservoirs. Jurassic sandstones of the North Sea, the Gippsland basin of Australia, the Gulf Coast Tertiary, the North Slope, and onshore China are several outstanding examples. This porosity is commonly a result of the dissolution of carbonate grains and cement. Figure 3-1 shows a dolomite grain in the process of being dissolved. Typically, it is assumed that these decementation reactions are the result of elevated. More difficult to explain is the removal of aluminosilicate framework grains. Figure 3-2 shows an excavated plagioclase grain with a portion of the authigenic K-feldspar rim still intact. The dissolution and removal of aluminosilicate framework grains is a problem of aluminum mobility, as aluminum is the least soluble major component. In the absence of complexing agents, pores and pore throats become blocked with reaction products, and no effective porosity enhancement occurs. Our experimental work with organic acids shows

The quality, quantity, type, and level of hydrocarbon maturation of various organic-rich rock samples were evaluated by two different techniques: elemental analysis and programmed pyrolysis. Eighty samples varying in both total organic carbon (0.5-75 wt% OC) and kerogen type were analyzed. Effects of the mineral matrix on measured geochemical parameters were examined by analysis of synthetic mixtures of separated kerogen (Types I, II, and III) and mineral matter (bentonite and illite at various percentages). Statistical analyses were performed on bulk rock samples, separated kerogen, and bitumen-extracted kerogen. Analyses include population descriptions, correlations, and stepwise multiple regression. Data parameters include: bulk rock Hydrogen Index (HI), sep-arated kerogen HI, bitumen-extracted kerogen HI, atomic H/C and O/C (bitumen-extracted kerogen), and % OC in bulk, separated, and bitumen-extracted samples. Results from a wide variety of hydrocarbon source rocks indicate that programmed pyrolysis can be used to predict atomic H/C. Although the variance of both methods is similar, the HI values derived from bulk rock samples consistently underestimate those derived from bitumen-extracted samples. Both measures are highly correlated ( r = 0.87, P = 0.001). Guidelines for the practical application of bulk rock pyrolysis data to source rock evaluation studies are presented. In summary, standard pyrolysis techniques yield information which can be used for rapid, accurate appraisal of the quality, maturity, and type of organic material contained within a wide variety of organic-rich rocks.

Geochemical and petrographic studies of core and cuttings samples from the Upper Cretaceous Ericson Sandstone in the Forest Oil, Jonah Gulch well, 9-26n-107w, reveal the presence of two distinct enhanced porosity zones that can be differentiated by their position relative to a paleo-oil/water contact. The evolution of enhanced porosity in these two zones can best be explained by experimentally predicted organic-inorganic chemical interactions. Both intragranular carbonate dissolution within chert clasts in the upper diagenetic zone and mixed-layer clay dissolution in the lower zone are apparently the result of organic-inorganic interactions. These interactions are the natural consequence of progressive burial of a sedimentary prism containing sand and shale. The sequences of inorganic diagenesis for the Ericson Sandstone reservoir and organic maturation in the adjacent shales were determined independently. Then, spatial, temporal, and textural relationships in conjunction with reaction temperatures were used to integrate the two sequences. The synthesis of the organic and inorganic systems shows that the two major porosity enhancement events can be directly tied to organic solvents produced by progressive maturation reactions. Dissolution of mixed-layer clay in the lower zone was associated with a pulse of organic acids generated prior to the formation and migration of most liquid hydrocarbons. These organic solvents—primarily carboxylic acids and phenols—complexed aluminum in the mixed-layer clay. This complexing action caused the destabilization and dissolution of the clay resulting in porosity enhancement. In the upper diagenetic zone, porosity enhancement occurred after hydrocarbon migration. The carbonic acid that dissolved carbonate within the chert grains was produced by thermal destruction of reservoired organic fluids in the upper Ericson. Thus, both porosity enhancement events can be related to organic solvents generated during progressive maturation. The interpreted organic-inorganic interactions and associated porosity enhancement events can be diagrammed using a clastic reaction pathway flow chart. The flow chart uses the four component system of CO 2 , organic acids, carbonates and aluminosilicates to illustrate the evolution of enhanced porosity through time. Use of such flow charts represents the initial step in predicting regions of maximum enhanced and preserved porosity in the subsurface.

Mineral oxidants are examined as possible agents for the production of water soluble organic solvents from kerogen in the course of progressive burial of sedimentary rocks. In particular, the diagenetic conversion of smectite to illite is quantitatively evaluated as an oxidation agent using data from the Texas Gulf Coast as well as experimental results. The reduction of mineral oxidants and consequent oxidation of organic matter may be as effective a mechanism in releasing peripheral difunctional carboxylic acid groups from the kerogen as thermal degradation in the natural system. Porosity enhancement in the subsurface is often limited by the ability of the diagenetic fluids to transport aluminum. Difunctional carboxylic acids (as well as other organic solvents such as phenols) complex aluminum, effectively increasing the solubility of aluminosilicate minerals. The solubility of carbonate minerals is also increased by these organic solvents. The coincidence in time, temperature, and space of mixed-layer smectite/illite transformations with peak concentrations of organic acids in oil field brines suggests a possible mechanism for the generation of difunctional carboxylic acids. This mechanism would allow highly soluble difunctional organic acids to pass through adjacent sandstones just prior to hydrocarbon generation. These acids are ideal solvents for dissolving carbonates and/or aluminosilicates out of pores and pore throats, thereby enhancing porosity and permeability in hydrocarbon reservoirs.

Abstract The subsurface hydrologic system of large, actively filling sedimentary basins includes meteoric, compactional, and thermobaric regimes. Boundaries between the regimes and their contained flow systems evolve as basin filling proceeds. As a result, sands are continuously flushed by a succession of fluids of varying origins and chemistries. Careful examination of the existing hydrologic setting and a reconstruction of generalized hydrologic history and its relationship to observed diagenetic features within a depositional sequence may serve to validate interpretive diagenetic models and may explain or predict paragenetic relationships, regional diagenetic variations within the same depositional episode, and differences in diagenetic products in different episodes in the same or similar basins. The Frio/Catahoula Formations of the Texas Coastal Plain provide an example that both illustrates the coexistence of hydrologic regimes and relates associations of diagenetic features with existing regimes or with the important mixing zones that occur between regimes. Hydrocarbon geochemistries indicate meteoric flushing to depths approaching 2000 m. The deeper geopressured section is coincident with a thermobaric regime in which clay dewatering recharges the hydrologically restricted portions of the basin fill.

Abstract Reservoir quality trends in Lower Tertiary sandstones along the Texas Gulf Coast are a product of regional variations in intensity of diagenesis. The major controls on diagenesis were detrital mineralogy and regional geothermal gradient. Porosity and permeability in sandstones shallower than 3350 m (11,000 ft) are generally adequate for hydrocarbon production, whereas reservoir quality in deeper sandstones in the onshore Lower Tertiary section is highly variable. Many of these sandstone reservoirs have permeability values of less than 1 millidarcy (md), but in a few areas permeability values are higher than 1000 md. Wilcox sandstones are poorly to moderately sorted, fine-grained, quartzose lithic arkoses, becoming more quartz-rich from the upper to the lower Texas Gulf Coast. Most rock fragments are metamorphic or volcanic in origin. Wilcox sandstones exhibit no systematic regional reservoir quality trends. Along the lower and parts of the middle and upper Texas Gulf Coast, deep Wilcox sandstones are tight, but in other parts of the middle and upper Texas Gulf Coast, porosity exists at depth. Vicksburg sandstones are poorly sorted, fine-grained lithic arkoses. Rock fragments are mainly volcanic clasts with lesser carbonate and minor metamorphic clasts. The deep Vicksburg Formation has low-quality reservoirs. Frio sandstones range from poorly sorted, fine-grained, feldspathic litharenites to lithic arkoses along the lower Texas Gulf Coast to poorly sorted, fine-grained, quartzose lithic arkoses to subarkoses along the upper Texas Gulf Coast. Volcanic and carbonate rock fragments are common in the lower Texas Gulf Coast and decrease in abundance up the coast. Frio sandstones show a systematic improvement in reservoir quality from the lower to the upper Texas Gulf Coast that is related to grain composition and geothermal gradient. Reservoir quality trends in Tertiary sandstones have been substantiated by acoustic log analysis. In spite of variations in composition, Lower Tertiary sandstones exhibit similar diagenetic sequences generalized as follows: Surface-to-shallow-subsurface diagenesis (0 to 1200 m ±; 0 to 4000 ft ±) began with the formation of clay coats on framework grains, dissolution of feldspar, and replacement of feldspar by calcite. Minor amounts of kaolinite, feldspar overgrowths, and Fe-poor calcite was locally precipitated. Porosity was commonly reduced by compaction and cementation from an estimated original 40% to less than 30%. Intermediate subsurface diagenesis (1200 to 3400 m ±; 4000 to 11,000 ft ±) involved dissolution of eary carbonate cements and subsequent cementation by quartz overgrowths and later by carbonate cement. Cementation commonly reduced porosity to 10% or less, but this trend could be reversed by later dissolution of feldspar grains, rock fragments, and carbonate cements. Restoration of porosity to more than 30% occurred, but some porosity was later reduced by kaolinite, Fe-rich dolomite, and ankerite cementation. Deep subsurface diagenesis (>3400 m ±; >11,000 ft ±) was a continuation of late Fe-rich and Fe-poor carbonate cement precipitation. Plagioclase was albitized during this stage. Differences in intensity of diagenetic events and depths at which they first occurred correspond to the chemical and mechanical stability of the original detrital mineralogy and to regional variations in geothermal gradient.

Abstract Burial diagenesis of Frio sandstones deduced from detailed study of one small area of the northern Texas Gulf Coast (Brazoria County, Milliken et al, 1981) is regionally valid with only minor modifications. Quartz is most commonly the first cement of volumetric significance to form, and constitutes 2.5% of the average sandstone volume. The average δ5 18 O of quartz cement is +31 o/oo± 1.5 o/oo (SMOW), indicating precipitation at considerably cooler temperatures than most clay mineral transformation takes place. Calcite is the dominant cement in Frio sandstones, constituting about 5% of the total sandstone volume, and most commonly postdates quartz precipitation. Calcite more depleted than −10 o/oo (PDB) is uncommon, and most calcite has a δ 18 O of −7.2± 2 o/oo (PDB). δ 13 C values cluster closely around −4 ± 2 o/oo (PDB). Because of relatively constant isotopic composition, and relatively invariant iron and manganese content in calcite, both areally and with depth, both quartz and calcite cements appear to have been emplaced under relatively invariant chemical conditions prior to hydrocarbon migration. Detrital K-feldspar is essentially absent below 12,000 ft, and the zone of plagioclase albitization extends between about 9000 and 12,000 ft. Virtually no unaltered detrital feldspars are present below 12,000 ft in any of the samples examined, K-feldspar having been mostly dissolved and plagioclase albitized. The volume of water required to precipitate quartz and calcite cements far from the apparent sources of material, generate secondary porosity and alter all detrital feldspars regionally in this thick sandstone sequence far exceeds the volume of pore water deposited with, near, or beneath the sands. Active thermally driven convection is a plausible (though unproven) mechanism for moving such large masses of dissolved components (and hydrocarbons) through the sandstones.

Abstract Sequences of diagenetic minerals associated with secondary porosity show striking similarities. The formation of quartz overgrowths on detrital quartz grains is generally followed by carbonate cementation. The dissolution of this carbonate is the main secondary porosity-forming event, which commonly precedes kaolinite precipitation and iron-rich carbonate cementation. In the Texas Gulf Coast, oxygen isotopic data provide temperature estimates of authigenic phases that predate and postdate secondary porosity development: quartz, ⩾ 80° C; kaolinite, ⩾ 70° C; albite, 100–150° C; late carbonate, > 100° C. These data suggest that secondary porosity in the Tertiary Gulf Coast forms at temperatures of about 100 ± 25° C. Correlations among calcite saturation indices in pore fluids, abnormally high permeabilities, and mole percent CO 2 in natural gases of the Eocene Wilcox Group imply a strong interrelationship between carbon dioxide and secondary porosity development in clastic reservoirs. The CO 2 content of gases varies systematically with both the reservoir age and temperature, which suggests a kinetic control on generation. The amount of CO 2 in natural gases increases rapidly at approximately 100° C; this coincides with a rapid increase in the ratio of secondary to total porosity in associated sandstones. Stable isotopic analyses of carbonate cements indicate a strong component of organically derived carbon and therefore cycling of carbon between inorganic and organic systems. The type, amount and distribution of organic matter, and early carbonate in both shales and sandstones control the quantity of CO 2 available for generating secondary porosity.

Abstract Oxygen- and carbon-isotope compositions have been determined for clay and carbonate minerals from the Upper Cretaceous clastic rocks of the Milk River and Lea Park Formations. These units contain the Milk River aquifer and the southeastern Alberta Milk River Gas Pool, respectively. The stable isotope data provide important information concerning the diagenesis and paleohydrology of the study area. Authigenic minerals from sandstones in the Milk River aquifer are characterized by low δ 18 O and δ5 13 C values: clay minerals (<2 μm), dominated by authigenic kaolinite, δ 18 O = +11.3 to + 14.2 (SMOW); authigenic calcite, δ5 18 O = +15.3 to +18.5 (SMOW), δ 13 C = −9.9 to −2.6 (PDB). The authigenic minerals with the lowest δ5 18 O values occur within a zone of local recharge in the aquifer. Here the authigenic clay minerals and calcite closely approach isotopic equilibrium with existing meteoric water at low temperatures (<+15°C). Low δ 13 C values forthe calcite indicate incorporation of organically derived CO 2 , probably from decaying plant material in the overlying soil and till. Close agreement between actual formation temperatures and those calculated from isotopic data disappears in downdip portions of the aquifer, mostly because of the drastic enrichment in 18 O of the formation water in this direction (−20 to −6, SMOW; Schwartz et al, 1981). Authigenic minerals from these locations have retained isotopic signatures characteristic of 18 O-poor meteoric water no longer present in the system. This water was displaced by 18 O-rich formation fluids that are themselves now being flushed from the aquifer by modern-day ground water. Authigenic minerals from sandstones in the southeastern Alberta Milk River Gas Pool are more 18 O-rich than those from the aquifer: clay minerals, dominated by illite, +14.7 to +15.8, SMOW; calcite, +19.3, SMOW. Such compositions are compatible with mineral crystallization at low temperatures (+15 to +20° C) from formation fluids similar in δ5 18 O to other Cretaceous oil and gas pools that occur in Alberta. The low- 13 C nature of authigenic calcite and some dolomite (−7.6 to −3.0, PDB) from the Milk River Gas Pool may be related to the production of biogenic methane in this reservoir. Of all clay minerals analyzed, the illite-dominated mixtures from argillaceous rocks of the Milk River aquifer and the Milk River Gas Pool have the highest δ 18 O values (+16.0 to +19.0, SMOW). Such compositions reflect a detrital origin rather than diagenetic processes. Isotopic exchange between these clay minerals and formation water is insignificant. Most dolomite from the sandstones and the argillaceous rocks is not in equilibrium with the authigenic calcite. The dolomite is much richer in 18 O (+24.4 to +28.3, SMOW) and 13 C (−2.7 to +1.0, PDB); such values are typical of platform carbonate rocks. No evidence for extensive isotopic exchange between formation water and the dolomite can be demonstrated.

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.