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