Showing papers in "AAPG Bulletin in 1979"

Plate tectonics and sandstone compositions

Abstract: Detrital framework modes of sandstone suites from different kinds of basins are a function of provenance types governed by plate tectonics. Quartzose sands from continental cratons are widespread within interior basins, platform successions, miogeoclinal wedges, and opening ocean basins. Arkosic sands from uplifted basement blocks are present locally in rift troughs and in wrench basins related to transform ruptures. Volcaniclastic lithic sands and more complex volcano-plutonic sands derived from magmatic arcs are present in trenches, forearc basins, and marginal seas. Recycled orogenic sands, rich in quartz or chert plus other lithic fragments and derived from subduction complexes, collision orogens, and foreland uplifts, are present in closing ocean basins, diverse succ ssor basins, and foreland basins. Triangular diagrams showing framework proportions of quartz, the two feldspars, polycrystalline quartzose lithics, and unstable lithics of volcanic and sedimentary parentage successfully distinguish the key provenance types. Relations between provenance and basin are important for hydrocarbon exploration because sand frameworks of contrasting detrital compositions respond differently to diagenesis, and thus display different trends of porosity reduction with depth of burial.

Deep-Water Sandstone Facies and Ancient Submarine Fans: Models for Exploration for Stratigraphic Traps

Abstract: Five main facies of deep-water clastic rocks can be defined: classic turbidites, massive sandstones, pebbly sandstones, conglomerates, and debris flows (with slumps and slides). The classic turbidites consist of monotonously parallel-interbedded sandstones and shales without channeling; internal sedimentary structures include grading, parallel lamination, and cross-lamination. Massive sandstones are thicker, coarser, and commonly channelized. They lack the sedimentary structures of classic turbidites, but do contain evidence of dewatering during deposition. Pebbly sandstones tend to be well graded, and can contain parallel stratification and large-scale cross-stratification. Conglomerates are characterized by inverse and normal grading, parallel and cross-stratification, nd commonly have a preferred clast fabric (imbrication). Both the pebbly sandstones and conglomerates commonly are channelized. The facies can be fitted into a model of submarine-fan deposition. Modern fans are subdivided into an upper fan (suprafan), characterized by (1) a single deep channel with levees, (2) a middle fan, built up from suprafan lobes that periodically switch in position, and (3) a topographically smooth lower fan. The suprafan lobes have shallow, braided channels on their inner parts, but the outer suprafan lobes are smooth, and grade basinward into the smooth lower fan and basin plain. The smooth suprafan lobes and lower fan are characterized by deposition of the classic turbidite facies, and the braided part of the suprafan lobes by massive and pebbly sandstones. When one lobe is abandoned and another starts to prograde elsewhere, the first lobe is blanketed by mud, forming a potential stratigraphic trap. The upper-fan channel is an area of coarse sediment deposition, or conglomerates where gravel and boulders are supplied to the basin. During fan progradation, thickening- and coarsening-upward facies sequences can be formed in a manner analogous to those of deltas. Fan channels also can be abandoned progressively, forming thinning- and fining-upward sequences similar to those of fluvial or distributary channels. These sequences can be identified on electric logs. Where basin shales act as hydrocarbon-source areas, the classic turbidites can act as conduits, leading the hydrocarbons to the thicker, laterally coalesced massive and pebbly sandstones of the braided suprafan lobes. These bodies can be of the order of 25 km in diameter, and up to 100 m thick. The coarse deposits of the upper-fan channel also might form good reservoirs, being bounded by shales (levee deposits) on either side, and possibly by shales above if the fan-channel system is abandoned. Such channels can be tens of kilometers long, several kilometers wide, and a few hundred meters deep. Reservoirs may be present in all of these environments.

Mechanics of Secondary Hydrocarbon Migration and Entrapment

Abstract: The mechanics of secondary hydrocarbon migration and entrapment are well-understood physical processes that can be dealt with quantitatively in hydrocarbon exploration. The main driving force for secondary migration of hydrocarbons is buoyancy. If the densities of the hydrocarbon phase and the water phase are known, then the magnitude of the buoyant force can be determined for any hydrocarbon column in the subsurface. Hydrocarbon and water densities vary significantly. Subsurface oil densities range from 0.5 to 1.0 g/cc; subsurface water densities range from 1.0 to 1.2 g/cc. When a hydrodynamic condition exists in the subsurface, the buoyant force of any hydrocarbon column will be different from that in the hydrostatic case. This effect can be quantified if the potentiome ric gradient and dip of the formation are known. The main resistant force to secondary hydrocarbon migration is capillary pressure. The factors determining the magnitude of the resistant force are the radius of the pore throats of the rock, hydrocarbon-water interfacial tension, and wettability. For cylindrical pores, the resistant force can be quantified by the simple relation: Pd = (2^ggr cos ^THgr)/R, where Pd is the hydrocarbon-water displacement pressure or the resistant force, ^ggr is interfacial tension, cos ^THgr is the wettability term, and R is radius of the largest connected pore throats. Radius of the largest connected pore throats can be measured indirectly by mercury capillary techniques using cores or drill cuttings. Subsurface hydrocarbon-water interfacial tensions range from 5 to 35 dynes/cm for oil-water systems an from 70 to 30 dynes/cm for gas-water systems. Migrating hydrocarbon slugs are thought to encounter water-wet rocks. The contact angle of hydrocarbon and water against the solid rock surface as measured through the water phase, ^THgr, is thus assumed to be 0°, and the wettability term, cos ^THgr, is assumed to be 1. A thorough understanding of these principles can aid both qualitatively and quantitatively in the exploration and development of petroleum reserves.

Seismic Evidence for Widespread Possible Gas Hydrate Horizons on Continental Slopes and Rises

Abstract: Anomalous reflections in marine seismic reflection data from continental slopes are often correlated with the base of gas hydrated sedimentary rocks. Examination of University of Texas Marine Science Institute reflection data reveals the possible presence of such gas hydrates along the east coast of the United States, the western Gulf of Mexico, the coasts of northern Colombia and northern Panama, and along the Pacific side of Central America in areas extending from Panama to near Acapulco, Mexico. Suspected hydrates are present in water depths of 700 to 4,400 m and extend from 100 to 1,100 m subbottom. Geometric relations, reflection coefficients, reflection polarity, and pressure-temperature relations all support the identification of the anomalous reflections as the base of gas hydrated sediments. In most places, gas hydrate association is related to structural anomalies (anticlines, dipping strata), which may allow gas to concentrate and migrate updip into pressure and temperature conditions suitable for hydrate formation. The gas hydrate boundary can be used to estimate thermal gradients. In general, thermal gradients estimated from the gas hydrate phase boundary are higher than reported thermal gradients measured by conventional means.

Structure and Stratigraphy of Forearc Regions

Abstract: Active continental margins and the active flanks of island arcs lie in the forearc regions of arc-trench systems generated by plate consumption. Arc-trench systems are initiated by contractional activation of previously rifted continental margins, by reversal of subduction polarity following arc collisions, and as island arcs within oceanic regions. The varied configurations of shelved, sloped, terraced, and ridged forearcs arise partly from differences in initial geologic setting, but mainly from differences in structural evolution during subduction. In regions where large quantities of sediment are delivered, forearc terranes enlarge during subduction through linked tectonic and sedimentary accretion of deformed ocean-floor sediments and igneous oceanic crust, uplifted rench-floor and trench-slope sediments, and the depositional fills of subsiding forearc basins. Where sediment delivery is small, enlargement is subdued or absent, and shortening of the arc-trench gap may be possible. Trench inner slopes typically are underlain by growing subduction complexes composed of imbricate underthrust packets of ocean-basin, trench-floor, and trench-slope sediments in thrust sheets, isoclines, and melanges. The structure of subduction complexes is governed by the thickness and nature of oceanic layers rafted into the subduction zone, variable thicknesses of trench and slope sediments, and the rate and obliquity of plate convergence. Forearc basins between the magmatic arc and the trench axis include (a) intramassif basins lying within and on basement terranes of the arc massif, (b) residual basins lying on oceanic or transitional crust trapped between the arc massif and the site of initial subduction, (c) accretionary basins lying on accreted elements of the growing subduction complex, (d) constructed basins lying on the arc massif and accreted subduction complex, and (e) a composite of these basins. Strata deposited in forearc basins are typically immature clastic sediments composed of unstable clasts derived from rapid erosion of volcanic mountains or uplands of plutonic and metamorphic rocks within the arc massif. In equatorial regions reef-carbonate associations are also common. Facies patterns of turbidites, shelf sequences, and fluviodeltaic complexes within forearc basins are governed by the elevation of the basin thresholds, the rate of sediment delivery, and the rate of subsidence of the substratum. Petroleum prospects in forearc regions typically are limited by the prevalence of small, obscure structures within the subduction complex, the scarcity of good reservoirs in the forearc basin, the limited occurrence of source beds, and low geothermal gradients except within the arc massif where heat flux is commonly excessive.

Structural Styles, Their Plate Tectonic Habitats, and Hydrocarbon Traps in Petroleum Provinces

Abstract: Broadly interrelated assemblages of geologic structures constitute the fundamental structural styles of petroleum provinces. These assemblages generally are repeated in regions of similar deformation, and their associated hydrocarbon traps can be anticipated prior to exploration. Styles are differentiated on the basis of basement involvement or detachment of sedimentary cover. Basement-involved styles include wrench-fault structural assemblages, compressive fault blocks and basement thrusts, extensional fault blocks, and warps. Detached styles are decollement thrust-fold assemblages, detached normal faults ("growth faults" and others), salt structures, and shale structures. These basic styles are related to the larger kinematics of plate tectonics and, in some situations, to particular depositional histories. Most styles have preferred plate-tectonic habitats: (1) wrench faults at transform and convergent plate boundaries; (2) compressive fault blocks and basement thrusts at convergent boundaries, particularly in forelands and orogenic belts; (3) extensional fault blocks at divergent boundaries in all stages of completion and certain parts of convergent boundaries; (4) basement warps in a variety of plate-interior and boundary settings; (5) decollement thrust-fold belts in trench inner walls and foreland zones of convergent boundaries; (6) detached normal faults, usually in unstable, thick clastic wedges (mostly deltas); (7) salt structures primarily in nterior grabens that may evolve to completed divergent boundaries; and (8) shale structures in regions with thick overpressured shale sequences. Important differences in trend arrangements and structural morphologies provide criteria for differentiation of styles. These differences also result in different kinds of hydrocarbon traps. Wrench-related structural assemblages are concentrated along throughgoing zones and many have en echelon arrangements. The basic hydrocarbon trap is the en echelon anticline, in places assisted by closure directly against the wrench fault itself. Compressive and extensional fault styles typically have multiple, repeated trends, which combine to form zigzag, dogleg, or other grid patterns. Their main trap types are fault closures and drape folds above the block boundaries. Basement warps (domes, arches, etc) are mostly solitary features and commonly provide long-lived positive areas for hydrocarbon concentration in broadly flexed closures. Most decollement thrust-fold structures are arranged in long, sinuous belts and are repeated in closely spaced, wavelike bands. Effective closures include slightly to moderately disrupted compressive anticlines and lead edges of thrust sheets. Most detached normal faults are listric faults that occur in coalescing, cuspate bands parallel with the strike of contemporaneous sedimentation. Their basic hydrocarbon traps are associated rollover anticlines which are uniquely concentrated along the downthrown sides of major faults. Salt and shale structures are present both as buoyantly rising pillows, domes, ridges, etc, and as highly complex injected features caused by tectonic forces. Stratigraphic factors, such as truncation, wedging, onlap, and unconformity, add to the variety of traps n all styles. In many places the structures of a petroleum province are either, or both, a gradation between the described fundamental styles and a mix of several styles. These structures can be further complicated by superimposition of fundamentally different tectonic environments. Additional modification of structures can result from still other factors inherent in the deformed region or in the particular tectonic event.

Late Triassic-Jurassic Paleogeography and Origin of Gulf of Mexico Basin

Abstract: The basic structural and stratigraphic framework of the Gulf of Mexico Basin was established during the Late Triassic and the Jurassic. During the Late Triassic and Early Jurassic, as the North American plate started to separate from the South American and African plates, the area of the future basin was part of an extensive landmass broken by tensional grabens that were filled by red beds and volcanics. Marine deposition was restricted to embayments of the Pacific Ocean in northwestern and central Mexico. These marine embayments persisted during the early Middle Jurassic, but seawater did not reach the future Gulf of Mexico Basin until the Callovian. Widespread salt deposits known today from two separate areas of the basin resulted from this initial flooding. During the ate Jurassic, marine conditions progressively extended over increasingly larger parts of the Gulf of Mexico Basin. However, the basin was not connected to the Atlantic Ocean until late in the Jurassic. This paleogeographic reconstruction suggests that the Gulf of Mexico Basin formed as a result of the southward drift of the Yucatan continental block away from the remainder of the North American plate. The separation began in the Late Triassic, continued slowly and sporadically during the Early and Middle Jurassic, and quickened after the Middle Jurassic salt formed. As a result, the salt deposits were split into the two segments known today, and oceanic crust formed in the center of the basin. Early in the Late Jurassic, the Yucatan platform reached its present position and the Gulf of M xico Basin was born.

Cretaceous ' oceanic anoxic events' as causal factors in development of reef- reservoired giant oil fields.

Abstract: Large amounts of organic carbon were de­ posited and preserved in marine sediments of late Bar- remian through middle Albian and late Cenomanian- earty Turonian age owing to the development of poorly oxygenated oceanic water masses and expanded oxy- § en minimum zones during "oceanic anoxic events." ediments rich in organic carbon which were depos­ ited during such events are thick sequences of basinal black shale or mudstone, thin black beds in shelf chalks, and thin beds and lenses in rudist reef and associated limestones. Analysis of the stratigraphic distribution of both known oil and giant oil-field reser­ voirs by many workers has indicated that a large part of the world's oil is of Mesozoic age and that most giant reservoirs are in rocks of Mesozoic age. We pro­ pose that the relative abundance of Mesozoic oil in the world oil picture is in part the result of maturation of organic carbon deposited during Cretaceous oceanic anoxic events. Many giant fields of Cretaceous age have reservoirs of shallow-water carbonate complexes such as rudist reef and associated fades buildups. We propose that the oil in such reservoirs originated as follows: (1) dur­ ing middle Cretaceous marine transgressions, equable world cHmate with high sea-surface temperatures pre­ vailed and led to carbonate reef buildups on shallow shelves and marginal platforms; (2) at the same time marine oxygen-nilnlmum zones expanded and deeper basinal oxygen deficits were Intensified owing to the lack of strong ocaanic mixing because of stable densi­ ty stratificatio n and possible low oceanic thermal gra­ dients; (3) these oxygen deficits enhanced the preser­ vation of organic carbon in basin, slope, and some shelf fades; (4) later Cretaceous transgression result­ ed in the drowning of the carbonate buildups which were then sealed under a cap of fine-grained hemipe- iagic sediment; interim regressions resulted In en­ hancement of porosity of reef fades and may have al­ lowed deposition of interbedded sand bodies in some sections; (6) many of these carbonate complexes and source beds were buried to suitable depths by Late Cretaceous and Tertiary clastic wedges and, depend­ ing on local geothermal gradients, hydrocarbon matu­ ration in the black stiale basinal fades occurred. These hydrocartions niigrated to shelf-edge reservoirs, such as platform cart)onate rocks, through intermediate fa­ des. This scenario with its combination of oceano- graphic and geokigic events led to development of fields such as those in the Golden Lane in Mexico. Thus, prime exploration targets are deeply buried ru­ dist buMuBs that are stratigraphically linked to basinal black shaw source tieds. Such buildups should be found on subsided passive margins of low to middle latitude regions; the source beds formed where nearly contemporaneous low-oxygen conditions obtained in adjacent basins.

Deep Basin Gas Trap, Western Canada

Abstract: Gas accumulations are distributed in a fashion similar to most other natural resources. The high-grade deposits are comparatively small. In general, as the grade decreases the size increases. Three of the largest sandstone gas fields in western North America are in low porosity-low permeability Cretaceous sandstone, in downdip structural locations, with porous water-filled reservoir rock updip. Examination of the details of these fields sets the stage for recognizing an enormous tight-sand gas trap in western Canada. The Mesozoic rock section, only 1,000 ft (300 m) thick on the shelf in eastern Alberta, thickens westward to over 15,000 ft (4,570 m) in the Deep Basin in front of the Foothills overthrusts. Most of the developed sandstone gas fields are in updip porosity traps, or minor structural traps, on the shelf. The porous, generally water-saturated sands of the shelf become less porous and permeable westward and downdip, passing from the water-bearing area with local gas traps through a transition zone to a gas-bearing area. This change is demonstrated by electrical resistivity logs and confirmed by drill-stem tests. Recent exploratory drilling in the Deep Basin has resulted in numerous discoveries in the area. Several hundred log analyses provide reliable data for measuring potential gas resources in the range of 400 Tcf. Recoverable gas at $2.00/Mcf net after royalty may reach 150 Tcf. The quantities of gas apparently present would be a major addition to the North American energy supply.

Determination of Organic Content of Appalachian Devonian Shales from Formation-Density Logs: GEOLOGIC NOTES

Abstract: The carbonaceous organic content of the Devonian shales of the Appalachian basin is an important parameter for determining the natural-gas resources of these rocks. To calculate organic content from formation-density logs, analyses of wire-line logs from seven wells in Ohio, West Virginia, Virginia, and Kentucky were compared to laboratory core analyses. These data show that organic content computed from density logs is as reliable and as accurate as that determined from core samples. The density-log method offers the advantage of continuous sampling of the vertically heterogeneous shale section and is based on wire-line logs which are common and readily available sources of data. Plots of gamma-ray intensity versus formation density are used to determine the applicabilit of the method at a given location and to identify individual intervals where the approach may not be valid. Available data indicate that the method can be used in a large area of the western Appalachian basin.

Compilation and Correlation of Major Thermal Maturation Indicators

Abstract: It is important in hydrocarbon exploration to interpret accurately the thermal maturation stage of sedimentary rocks. A compilation and correlation chart shows the relations of the most commonly used organic and mineral thermal indicators with respect to the degree of maturation. The chart and the discussion of the limitations of each technique are based on the results published by other workers and on the writers' observations.

Thickness of Removed Sedimentary Rocks, Paleopore Pressure, and Paleotemperature, Southwestern Part of Western Canada Basin

Abstract: The thickness of sedimentary rocks removed by erosion in the geologic past can be evaluated by the use of shale-compaction data, such as the shale transit-time values recorded by sonic logs. The pore pressures in shales also can be calculated using compaction information. Integration of these shale-compaction data with homogenization temperatures of fluid inclusions in quartz infilling of fractures in sandstone, as discussed by Currie and Nwachukwu, makes possible the estimation of the paleotemperature and paleogeothermal gradients in a basin. Such an integrated study in the southwestern part of the Western Canada basin shows that (1) significant erosion in the geologic past removed as much as 4,600 ft (1,400 m) of the uppermost part of the sedimentary rocks; (2) significant undercompaction and overpressure were present in the deeper part of the Cretaceous section in the past; (3) the Cardium sandstone, which has a temperature range of about 140 to 160°F (60 to 71°C) at present, had much higher temperatures of about 300°F (149°C) at the time of maximum burial (before erosion); and (4) the geothermal gradient probably has not changed significantly in the geologic past.

Oil and Gas Migration--Chemical and Physical Constraints

Abstract: Primary migration of oil in aqueous solution is not possible because the composition of dissolved hydrocarbons is vastly different from that of crude oils. Migration of oil solubilized in surfactant micelles is also rejected because of the large amount of surfactant required, and because there has been no demonstration that micelles are formed in source rocks. Migration by oil-droplet expulsion also is not feasible, because of the high interfacial forces of small droplets within fine-grained source rock; in addition, at least 7.5% organic matter by volume would need to be converted to oil to attain 30% oil saturation required for separate-phase flow; even higher oil saturations would be required for "squeezing" oil from pores. It is proposed that oil and gas are generated in, and flow from, source rock in a three-dimensional organic-matter (kerogen) network. Oil or gas flowing in this hydrophobic network would not be subject to interfacial forces until it entered the much larger water-filled pores in the reservoir rock. Oil saturation in the kerogen for oil flow to occur is indicated to be from 4 to 20%. Secondary migration of separate-phase oil and gas should occur by buoyancy, when their saturations attain 20 to 30% along the upper or lower surfaces of the reservoir rock. Oil or gas entering at the lower surface would intermittently cross the rock when the buoyancy head became sufficient. Efficient migration from source to trap could then occur as rivulets along the upper few centimeters in the reservoir rock. The volume of conducting reservoir rock attaining oil or gas saturation during secondary migration should be small, with most of the pores remaining water filled. In contrast, secondary migration of gas or oil in solution would be very inefficient and require large volumes of water. Unless all pores in the reservoir rock attained 20 to 30% gas or oil saturation, separate-phase flow could not occur, and oil and gas would remain locked in the pores and would not form reservoirs in trap positions. Attaining a 30% pore volume (PV) gas or oil saturation would require a flow of about 90 to 200 PV of gas-saturated water, and 15,000 to 200,000 PV of oil-saturated water. Residual gas and oil in cores taken along suspected secondary-migration pathways should show this residual gas or oil saturation, and recovered water should always contain equilibrium concentration of dissolved hydrocarbons, but this has seldom been observed. The proposed mechanisms of primary migration of oil and gas through a kerogen network, and secondary migration by separate-phase buoyant flow do not require the flow of water. Water flow probably disperses water-soluble constituents instead of concentrating them in reservoir traps.

Effects of Texture and Composition on Mechanical Behavior of Experimentally Deformed Carbonate Rocks

Abstract: Dry, low-porosity carbonate rocks with a wide range of texture and dolomite content were experimentally deformed at room temperature, strain rate of 10-4 sec-1, and at confining pressures of 0, 50, and 100 MPa (1 MPa = 10 bars = 145 psi) to evaluate the effects of texture and composition on ultimate strength and ductility. Of all the factors considered, weighted mean grain size and microcrystalline carbonate (micrite) content have the highest linear correlation coefficients with ultimate strength. Grain size is, therefore, the dominant intrinsic rock property that affects ultimate strength in low-porosity carbonate rocks. Systematic increases in total dolomite content (determined by X-ray diffraction) do not correlate significantly with ultimate stre gth when all of the variously textured rocks are compared. However, ultimate strength does increase with increasing dolomite content in rocks of similar texture. The approximate ultimate strengths of carbonate rocks with intermediate dolomite and/or micrite content can be predicted by the best-fit plane to the ultimate strengths of "pure end members" (Yule marble, Solenhofen limestone, Hasmark dolomite, Blair dolomite). For experiments at 100 MPa confining pressure, this plane is defined by the equation: 0.90 D + 2.07 M + 269 = ^sgru, where D is dolomite content in percent, M is microcrystalline carbonate content in percent, and ^sgru is ultimate strength in MPa. The equation of the plane defined by ultimate strengths of rocks of intermediate composition and texture is: 1.07 D + 2.29 M + 258 = ^sgru. The mean difference between the strengths predicted by these two planes is only 9 MPa. Most precursive microfractures in nonmicritic elements are intragranular. Although the density of intragranular microfractures increases with increasing confining pressure, grain boundary cracks are suppressed by confining pressure. Very few microfractures occur in the micrite itself. At a given confining pressure, highly micritic rocks exhibit much less abundant precursive microfractures than coarser grained rocks, and hence they are stronger.

Effect of Oil and Bitumen Saturation on Source-Rock Pyrolysis

Abstract: Mass production of pyrolysis instrumentation such as the "Rock-Eval" has led to general application of whole-rock pyrolysis as a means of identifying and characterizing petroleum source beds. One of the problems inherent in the whole-rock technique is the effect of petroleum or bitumen on the measured amount of thermally extracted hydrocarbons from the kerogen. Under pyrolysis, migrated oil or bitumen in the rock gives a major response near 250 to 350°C on the program (S1). However, solid bitumen and the "heavy-end" fraction of petroleum produce a measurable response (S2) in the 350 to 450°C range as well as in the same region where kerogen conversion to hydrocarbons occurs. Thus, large quantities of bitumen or migrated petroleum in rocks can affect the size and the maximum temperature of the S2 peak and can cause nonsource rocks to be misidentified as source rocks. These problems can be overcome by rinsing the sample in a chlorinated hydrocarbon solvent prior to analysis.

Major Subdivisions and Depositional Environments of Nubia Strata, Southwestern Egypt

Abstract: Nubia strata in southwestern Egypt are more than 1,000 m thick and range in age from Jurassic to Late Cretaceous. Throughout much of the area, the interval can be subdivided into six distinct and traceable units. Three medium to coarse-grained sandstone units 100 to 500 m thick are interpreted as alluvial-plain deposits composed of cross-stratified shallow channel and massive rooted flood-plain cycles. Overlying each of these sandstone units is a siltstone or shale unit which is of marine, marginal-marine, or coastal-plain origin. These marine-influenced units suggest transgressions of latest Jurassic, middle Cretaceous, and latest Cretaceous ages, possibly correlative with worldwide eustatic sea-level rises. Because of extensive floral remains, the climate is thought to ave been warm and humid to semihumid. There is no evidence of aridity during the Jurassic or Cretaceous in this area. Southwestern Egypt contains the most extensive Nubia exposures in Egypt and is very favorable for dating, subdivision, and interpretation of these strata.

Migration of Fluids in Sedimentary Basins

Abstract: The basic mechanisms governing the migration of water and hydrocarbons in sedimentary basins are related ultimately to basinal structural history, rock properties, compaction, and temperature regime, which themselves are interdependent. Compaction of the sedimentary rocks promotes the expulsion of water during the progressive burial of the sediments. The physical-chemical properties of the rocks are responsible for the migration of the expelled water toward the surface and for the distribution in the basin of various parameters such as hydraulic potential, salinity, heat flow, temperature, and cementation. Primary migration is used herein to refer to migration of hydrocarbons soon after their generation; secondary migration refers to their delayed movement. Oil has difficulty migrating in shaly rocks. A possible way of removing oil from a source rock, in addition to the colloidal or true solubilization in water or the flow in a three-dimensional oil-wet kerogen network, is through its solubilization in high-pressure gas generated in the deeper part of the basin and coming up through preferential paths such as faults and fractures. Molecular distillation of the oil occurs because its vapor pressure in the liquid phase is higher than the vapor pressure in the gaseous phase. In the upper part of a lithologic column, retrograde condensation occurs and gas and condensate accumulations start to form below little compacted plastic caprocks. Owing to the high displacement pressures of the gaseous column, gas can pass through the caprock and disperse to the surface while the condensate remains in place. The pore-size distribution of the little compacted shaly caprock is responsible for the chemical and isotopic fractionation of the rising gas; almost pure and isotopically light methane thus is found in the upper layers of a stratigraphic column. High-volatile oil can be easily degraded by circulating water, especially in the presence of sulfate ions, hydrogen sulfide, and bacteria, and transformed progressively to heavy oil. Geochemical tools which can be used by explorationists in prospecting for new oil and gas fields include isotope analysis, hydraulic potential, salinity, temperature, cementation, maturity, and maps of shows.

Salt Movement on Continental Slope, Northern Gulf of Mexico

Abstract: Regional sparker lines across the continental slope of the northern Gulf of Mexico demonstrate the close relation between salt movement and sediment deposition. Salt features on the outer slope are not as well developed as those near the shelf because sedimentation has been much less on the slope. Salt-generated structures in the eastern part of the gulf are more mature than those in the western gulf because of higher rates of sedimentation. The youngest salt features on the outer slope are much larger than domes on the shelf. Seismic data from the outer slope suggest that salt dome growth in this area was initiated by southward salt flowage caused by sediment loading updip. The Sigsbee Escarpment appears to be a salt scarp (formed by this gulfward salt flowage) that has extruded over younger sediments for a considerable distance. Areas of salt diapirs in the Gulf of Mexico, with the exception of diapirs on much of the lower continental slope, are considered to be areas of original thick salt deposition. It is suggested that these areas of thick salt were deposited in one central rift in Jurassic time, and have moved to their present position by seafloor spreading. The present Red Sea is a model for the Gulf of Mexico at the time of Mesozoic breakup.

Aeromagnetic Detection of Diagenetic Magnetite over Oil Fields: GEOLOGIC NOTES

Abstract: High-wave-number magnetic anomalies measured as part of an airborne magnetic survey over the Cement oil field, Oklahoma, are interpreted as reflecting abundant near-surface magnetite formed by the reduction of hydrated iron oxides and/or hematite as a direct result of petroleum microseepage. Airborne geophysical methods provide an economically sound way to prospect for resources (Craib, 1972; Maxim and Cullen, 1977). In this report we suggest a correlation between high-wave-number anomalies observed on profiles from an airborne magnetic survey over the Cement oil field, Oklahoma, and the near-surface diagenetic formation of magnetite as a direct result of hydrocarbon microseepage from underlying reservoirs. This is especially interesting because, for most petroleum exploration applications, magnetic anomalies originate in crystalline basement rocks beneath the sedimentary cover. The Cement oil field is located in the southeast part of the Anadarko basin in Caddo and Grady Counties. The Cement structure is a northwest-southeast doubly plunging asymmetric anticline that has two distinct domes (East Cement and West Cement); it is bounded on the north flank by a large thrust fault. Oil and gas production is from Permian sandstone and Pennsylvanian carbonate and clastic rocks which range in depth from about 600 to 2,270 m. The reservoirs at Cement were shown previously to have undergone long-continued microseepage resulting in diagenetic alteration of the shallow overburden (Donovan, 1974; Donovan and Dalziel, 1977). Flight-line profiles of airborne measurements (flown at 120 m) of the earth's total magnetic field over the Cement area display anomalous high-wave-number peaks suggesting a shallow source (Fig. 1). Because the magnetic susceptibility of sedimentary rocks is largely a measure of their magnetite content, we conducted a systematic search for magnetite in borehole cuttings collected during the development of the oil field. Ferromagnetic material was separated magnetically from crushed samples taken from cuttings from the uppermost 300 m of five boreholes and composited at ~30-m intervals. Samples from depths less than about 80 m were not preserved. X-ray diffraction of the separated material confirmed it to be magnetite. Over the anticline, the amount of magnetite in the rocks appears to increase near the surface (Figs. 2, 3). We suggest that the slow but long-continued leakage from a petroleum or natural gas reservoir of hydrocarbons and/or associated compounds causes a chemical reducing environment in the overlying rocks and the consequent reduction of hydrated ferric oxides and hematite to form magnetite. Hematite and hydrated ferric oxides are common as grain coatings and bonding agents in clastic sedimentary rocks. Many ferric oxides are stable in the oxidizing zone, but in reducing environments they undergo reduction and release the more soluble ferrous iron in solution. A relatively large loss of iron through reduction and dissolution results in rocks that appear "bleached" or tinted. However, not all ferric iron may undergo reduction and dissolution. We postulate, schematically, that a sequence of a teration may take place as follows: hydrated ferric oxides ^rarr hematite (Fe2O3) ^rarr magnetite (Fe+2 Fe2+3 O4) Comparison of the Cement aeromagnetic data with aeromagnetic data from the smaller but End_Page 245------------------------------ Fig. 1. A, Selected segments of magnetic profiles from Cement oil field aeromagnetic survey. Cement structure is located on northeast flank of Anadarko basin and magnetic profiles probably reflect rise of magnetic basement to north (compare with map of Jones and Lyons, 1964). High-wave-number peaks are readily observable in profiles over crest of structure presumably where maximum formation of diagenetic magnetite took place. For comparison, 214Bi/208T1 profile (flight line ML34) from airbornegamma radiation data collected simultaneously with magnetics is also shown (bold line). Anomalously high 214Bi/208T1 ratios along crest owe their origin to late diagenetic uranium mineralization associated with petroleum microseepage (McKay and Hyden, 1 56; Donovan et al, 1975; Al-Shaieb et al, 1977). B, Oil field structure contoured on top of Hoxbar Formation (Pennsylvanian) modified from Donovan (1974), flight-line segments for magnetic profiles, and boreholes sampled for magnetite. Contour interval is 1,000 ft (~333 m). End_Page 246------------------------------ equally densely developed Davenport oil field of Lincoln County, Oklahoma, indicates that the phenomenon is not due to cultural interferences (pipelines, storage tanks, casing, etc), because no high-wave-number anomalies are seen in the Davenport data. Supporting evidence for the diagenetic formation of magnetite exists at Cement. The evenly red-colored Permian Rush Springs Sandstone is remarkably bleached at the surface, in a pattern that closely coincides with the area of oil and gas production; within this tinted area it is relatively depleted of iron. Along the crest of the surface-expressed anticline, the normally friable Rush Springs is strongly impregnated with carbonate cements (mostly calcite), whose C13/C12 isotopic ratios indicate a petroleum-derived carbon source. A thin overlying gypsum bed has been converted to calcite with similarly indicative C13/C12 ratios (Donovan, 1974). Pirson (1975) proposed that magnetoelectric effects may occur at the interface between the chemically reduced rock overlying a seeping hydrocarbon deposit and the oxidized rock surrounding the deposit, that is, an active process occurs whereby a giant fuel cell generates magnetoelectric effects. The phenomenon we describe has a different origin; namely, the diagenetic production of a ferromagnetic mineral that is a "fossil" indicator of microseepage. Search elsewhere for anomalous concentrations of diagenetically produced materials could be useful to explorationists. Fig. 2. Relations between magnetite (plotted as weight percent of total sample) and drilled depth for five boreholes at Cement oil field. Position of wells is shown in Fig. 1B. Samples were composited from drill cuttings collected ~15 m above and below plotted center point. Fig. 3. Probable range of magnetite with depth in near-surface rocks at Cement oil field along and near anticlinal crest. Only data from four boreholes along crest are plotted. End_Page 247------------------------------

Frigg Field--Large Submarine-Fan Trap in Lower Eocene Rocks of North Sea Viking Graben

Abstract: In the deepest, axial part of the Viking subbasin of the North Sea, the Frigg field, one of the world's largest offshore gas fields, straddles the border of the British and Norwegian continental shelf at lat. 60°N. The discovery well was drilled in 1971 on Norwegian block 25/1 in 100 m of water. Gas was discovered at a depth of 1,850 m in a lobate submarine fan representing the ultimate phase of a thick Paleocene deposit. Sealed by middle Eocene open marine shales, the structure is mainly submarine-fan depositional topography enhanced by draping and differential compaction of sands. The area of structural closure is underlined by a typical "flat spot" on seismic sections and the gas column lies on a heavy oil disk. Chromatographic analysis shows that both oil and gas could be coming from underlying Jurassic source rocks. Recoverable gas reserves are estimated to be about 200 billion cu m (7 Tcf). Production began September 15, 1977; the gas is brought ashore at St. Fergus in Scotland by a 360-km pipeline.

Aqueous Solubility of Methane at Elevated Pressures and Temperatures

Abstract: This study reports the solubility of methane in distilled water from 150° to 350°C and from 100 to 28,600 psi (689.5 to 197,197 kPa). Methane solubility greatly increases with increasing temperature above 250°C to maximum values of over 800 standard cu ft (22.66 cu m) of methane per barrel of water at 354°C and 28,600 psi (197,197 kPa). These high methane solubilities suggest that dissolved methane in the pore waters of sediments buried at 20,000 ft (6.10 km) and deeper in the Gulf Coast and other sedimentary basins could be a significant energy resource. These solubilities are also consistent with the concept of primary migration of natural gas and crude oil by molecular solution from the deep sediments of petroleum basins.

Lateral and Vertical Facies Relations of Transgressive Barrier

Abstract: Identification of transgressive barrier sequences in the stratigraphic record is important because preserved barriers are potential reservoirs of petroleum. The transgressive barrier complex on the Atlantic Coast of Delaware lies at the edge of the ongoing Holocene relative rise in sea level. The Delaware coastal zone is on the northwest flank of the subsiding Baltimore Canyon Trough geosyncline of the Atlantic continental shelf. Four major variants of a transgressive barrier complex in this area are (1) a spit-beachdune complex, (2) barrier overriding a coastal marsh, (3) beach against pre-Holocene highland, and (4) a barrier-tidal delta-lagoon system which includes a linear baymouth barrier and a lobate tidal delta. Characteristic vertical sequences in each of these var ants indicate that this barrier originated farther seaward and migrated landward to its present position. Coarse sediments overlying fine sediments, generally believed to be characteristic of regressive barriers, also are present in this transgressive example. Time lines clearly diverge and cross lithologic boundaries in both transgressive and regressive barrier sedimentary units. Hence, the transgressive or regressive nature of a preserved barrier sequence cannot be positively identified on the basis of characteristic shapes of geophysical logs or sedimentary sequences. Rather, projection of barrier trends must be based on a synthesis of barrier morphology, precise identification of elements of barrier stratigraphy, knowledge of time versus stratigraphic units and lateral and vertical s quences, and an understanding of sedimentary basin tectonics.

Errors in Extrapolation of Experimental Kinetic Parameters to Organic Geochemical Systems: GEOLOGIC NOTES

Abstract: Activation energy, a chemical kinetic parameter calculated for high-temperature pyrolysis reactions, cannot be extrapolated to low-temperature geologic systems via the Arrhenius equation, k = Ae -E RT , for several reasons. The assumption of temperature independence of A and E is valid only over a short temperature range. Multiple reaction mechanisms may be competing, with one reaction controlling the kinetics in one thermal regime while a different reaction may be controlling in a different thermal regime. Temperature dependence of diffusion, and transition-state reversibility may also result in different kinetic parameters being applicable to a given reaction at different temperatures. Therefore, the observed lower activation energy of a geologic system (compared with laboratory simulations) may be due to theoretical, chemical, and physical variables and cannot be attributed solely or even significantly to clay catalysis. Estimation of geologic temperatures and other geologic parameters from pyrolysis kinetics data is similarly and equally perilous.

Depositional History of Paleocene--Lower Eocene Flagstaff Limestone and Coeval Rocks, Central Utah

Abstract: The Flagstaff Limestone of Paleocene and early Eocene age, and coeval rocks of the North Horn and Colton Formations of central Utah, were deposited in the Lake Flagstaff lacustrine-alluvial complex. The Flagstaff lake basin formed in response to postorogenic deformation along the Sevier thrust belt and Laramide basement uplifts that blocked drainage. The Flagstaff Limestone of the Wasatch Plateau consists of three members; the lower member, designated Ferron Mountain, and the upper, the Musinia Peak, represent major high stands of the lake. They consist of mudstone, brecciated and massive carbonate rock with rootlets and pedogenic features, laminated and structureless limestone, fossiliferous limestone, and oncolitic and sandy limestone. During deposition of the Ferron Mo ntain Member, the eastern margin of the lake was vegetated, very shallow, and episodically exposed. In contrast, a relatively steep, high-energy shoreline along active structural elements bounded the west side of the lake. The middle member, designated Cove Mountain, consists of mud-cracked dolomicrite, mudstone, and bedded and nodular gypsum. These beds reflect repeated contractions and expansions of the lake across a broad carbonate mud flat. Freshwater limestones that were deposited during expansions of the lake probably were altered to dolomicrite during contractions by evaporative pumping of brine on mud flats.

Reservoir Properties of Conglomerates and Conglomeratic Sandstones: GEOLOGIC NOTES

Abstract: Bimodal clastic sedimentary rocks can be either "sand packed," where pebbles are dispersed through a continuous sandstone matrix, or "pebble packed," where sandstone partially or wholly fills the interstices between a framework of densely packed pebbles. The primary porosity of bimodal reservoir rocks may vary by a factor of 3 to 4, depending on the packing state and the relative proportions of sand and pebble-sized grains in the rock. The relations between permeability and porosity, and water saturation and porosity, in bimodal reservoir rocks may be quite different from those common in clastic reservoirs having unimodal grain-size distributions. The effects of bimodality and diagenesis should be considered separately for a better understanding of the properties of bimod l reservoir rocks.

Methods of Estimating Oil and Gas Resources

Abstract: Assessment of undiscovered oil and gas potentials can be made and presented in a probability format reflecting the inherent uncertainties and risks. A cumulative probability curve shows the chances of occurrence of possible hydrocarbon volumes, the risk that there is little or no potential, the average or expected value, and the "highside" potential. Such a curve can be drawn directly as a delphic consensus of expert opinions. Preferably, however, a curve can be constructed by multiplying, in a Monte Carlo simulation, several factors whose product is potential barrels of oil or cubic feet of gas. Each factor is entered as a range of values whose spread depends on the uncertainties. An example is the multiplication of the possible volumes of prospective sedimentary rock (e g., in cubic miles) by their potential hydrocarbon yields (e.g., barrels per cubic mile). Other geologic approaches depend mainly on estimated volumes of subsurface hydrocarbon trap space, on areal yields, on geologic analogies with other producing areas, on summation of individual prospect assessments, on the numbers and sizes of potential fields, or on the geochemical material balance of hydrocarbons generated, migrated, and trapped. More purely statistical methods involving the extrapolation of past discovery rates can be used only in maturely explored areas where data are abundant.

Submarine Slumping in Continental Margin of Israel and Northern Sinai

Abstract: The continental margin of Israel has the shape of a lens with foreset structure. The lens was formed by accumulation since Pliocene time of mainly fine clastics derived from the Nile and transported by the counterclockwise currents of the southeastern Mediterranean. After first deposition the detritus was redistributed over the continental slope by slumping and gliding. The slumping occurred, and still takes place, in the form of block and slab sliding, rotational slumping, mudflows, debris flows, and mass creep. These processes are earthquake triggered. They result in a scarred and undulating topography of the continental slope. Gigantic deep-seated, compound, rotational slumps have been observed in seismic profiles where a thick Pliocene-Quaternary sediment sequence overlies thick Messinian evaporites. The slumping modifies the original foreset structure of the young sediments along a sizable part of the continental margin of Israel. Excessive pore pressures generated by the Pliocene-Quaternary load in fine clastic layers interbedded within the impervious evaporites probably caused instability and consequent evaporite flow and rotational slumping of the cover sediments.

Strandline Sedimentation of Carbonate Grainstones, Upper Pleistocene, Yucatan Peninsula, Mexico: GEOLOGIC NOTES

Abstract: An ancient beach-ridge plain along the eastern Yucatan Peninsula is underlain by a body of carbonate grainstones 150 km long, 0.5 to 4 km wide, and 3 to 10 m thick. Primary structures and textures suggest that these calcarenites are a regressive sequence deposited in the nearshore and beach zones of a high-energy coast environment. Their accumulation built a strand plain along the prograding Yucatan coast during the late Pleistocene high stand of sea level. In typical vertical sequence (from bottom to top) the upper Pleistocene calcarenite deposits consist of: (a) lower shoreface--low-angle cross-bedded, burrowed bioclastic, fine-coarse calcarenite with calcirudite lenses; (b) upper shoreface--multidirectional trough cross-bedded, bioclastic, pelletoid, and oolitic, fine to coarse calcarenite with calcirudite layers containing shells, corals, caliche lithoclasts, and intraclasts of beachrock; and (c) foreshore-backshore--parallel-laminated oolitic, bioclastic, and pelletoid, fine to medium calcarenite with rhizocretions in the upper part and caliche crusts at the top. In the southern part of the study area the strand-plain grainstones overlie nonbedded bioclastic calcarenite and micrite that were deposited in the offshore between the mainland and a coral barrier reef which fringed the shelf edge. This section overlies thin, discontinuous caliche clast-shell-coral calcirudites (transgressive lag), which lie on a pholad- and sponge-bored subaerial crust (caliche) developed on older limestones. Farther north the strand-plain calcarenites lie directly on the subaerial crust. The shoreface section is largely storm deposits composed of material derived both from offshore and from the shoreline. Storm waves also probably deposited much of the foreshore calcarenite. Thinly coated ooids that are concentrated in the beach and inner-shoreface deposits probably were coated in the high-energy nearshore. These coastal-zone limestones show that significant volumes of porous and permeable carbonate grainstone can be accumulated by seaward advance of the shoreline during high stands of sea level. Ancient strandline grainstones are potential hydrocarbon reservoirs in updip carbonate sequences.

Nubia Formation of Central Eastern Desert, Egypt--Major Subdivisions and Depositional Setting

Abstract: The Nubia Formation of the central Eastern Desert is a record of predominantly nonmarine sedimentation in response to local and regional structural movements during the Late Cretaceous. The Nubia section of the Eastern Desert can be divided into five major lithologic units, in ascending order: (1) basal unit of fluvial trough-cross-bedded conglomeratic sandstone (absent near Safaga); (2) coastal and marginal-marine gray and red shale and thin sandstone (restricted to Aswan area); (3) fluvial tabular-cross-bedded sandstone; (4) coastal fluvial-plain and delta-plain ripple-laminated siltstone and lenticular fine-grained sandstone; and (5) coastal and marginal-marine clay-shale and siltstone. Facies relations and cross-bed directions in the lower Nubia suggest that, during the middle Cretaceous (Cenomanian?), fluvial sediments were transported westward from highlands in the area of the present Red Sea and southward from uplifted areas north of Aswan and near Safaga. The Cenomanian transgression from the northwest reached the vicinity of Aswan, where marginal-marine sediments interfingered with fluvial deposits from the east. Later, uplift in the area south of the Eastern Desert and subsidence of the northern margin of the African shield caused the streams to flow northward, spreading a blanket of sandy fluvial sediment over the entire area now between the Red Sea and the Nile Valley. As the supply of sediment from the south continued, progressively finer terrigenous materi l reached the region that is now the Eastern Desert. During the Campanian, fine-grained coastal fluvial-plain and delta-plain sediment interfingered to the north with coastal muds. Continued subsidence of the northern flank of the Egyptian shield and the Late Cretaceous eustatic rise in sea level brought deposition of coastal mud progressively farther south.

Differential Entrapment of Oil and Gas in Niagaran Pinnacle-Reef Belt of Northern Michigan

Abstract: The Niagaran pinnacle-reef belt in the northern part of the Michigan basin is about 170 mi (270 km long) and 10 to 20 mi (16 to 32 km) wide. Since 1969, 360 oil- and gas-producing reefs and 72 salt-plugged or otherwise barren, water-saturated reefs have been found in the belt. The reefs are of small areal extent (average 80 acres; 32 ha.), high relief (up to 600 ft; 180 m), and steep flanks (30 to 45°) and are effectively sealed by the lower Salina evaporite deposits. The reefs are hydraulically interconnected through the Lockport Formation, their common permeable substrate, which dips basinward at 70 to 140 ft/mi (13 to 26 m/km; 0.76 to 1.52°). Reef height, pay thickness, burial depth, reservoir pressure, hydrogen sulfide content, and extent of salt plugging in rease progressively in a basinward direction across the belt, whereas oil gravity and degree of dolomitization increase systematically in the opposite direction. The belt is distinctly partitioned in an updip direction into three parallel bands of gas-, oil-, and water-saturated zones. This zonation of reservoir fluids is in full accord with Gussow's classic theory on the differential entrapment of oil and gas and provides a textbook example of its applicability on a regional scale in a natural case history. Interruptions in the continuity of the water-saturated band are interpreted as indicating passageways through which hydrocarbons may have migrated farther updip into the carbonate-shelf platform bounding the pinnacle-reef belt on the north. This reasoning leads to the delineation of two additional favorable target areas for further exploration.