Showing papers on "Petroleum reservoir published in 1986"

Wettability Literature Survey- Part 1: Rock/Oil/Brine Interactions and the Effects of Core Handling on Wettability

Abstract: Wettability is a major factor controlling the location, flow and distribution of fluids in a reservoir. The wettability of a core will affect almost all types of core analyses, including capillary pressure, relative permeability, waterflood behavior, electrical properties, and simulated tertiary recovery. The most accurate results are obtained when native- or restored-state cores are run with native crude oil and brine at reservoir temperature and pressure. Such conditions provide cores that have the same wettability as the reservoir. The wettability of originally water-wet reservoir rock can be altered by the adsorption of polar compounds and/or the deposition of organic material that was originally in the crude oil. The degree of alteration is determined by the interaction of the oil constituents, the mineral surface, and the brine chemistry. The procedures for obtaining native-state, cleaned, and restored-state cores are discussed, as well as the effects of coring, preservation, and experimental conditional conditions on wettability. Also reviewed are methods for artificially controlling the wettability during laboratory experiments.

Relative Permeability Of Petroleum Reservoirs

Abstract: This book enables petroleum reservoir engineers to predict the flow of fluids within a hydrocarbon deposit. Laboratory techniques are described for both steady-state and unsteady state measurements, and the calculation of relative permeability from field data is illustrated. A discussion of techniques for determing wettability is included, along with theoretical and empirical methods for the calculation of relative permeability, and prediction techniques. Contents include: Measurement of Rock Relative Permeability; Two-Phase Relative Permeability; Factors Affecting Two-Phase Relative Permeability; Three-Phase Relative Permeability; and Index.

Upper Permian (Guadalupian) Facies and Their Association with Hydrocarbons--Permian Basin, West Texas and New Mexico

Abstract: Outcrops of Guadalupian sedimentary rocks in the Permian basin of west Texas and southeastern New Mexico are a classic example of the facies relationships that span a carbonate shelf. In the subsurface, these rocks form classic hydrocarbon-facies traps. Proceeding from basin to the updip termination of the shelf, the facies are (1) deep-water basin, (2) an apron of allochthonous carbonates, (3) carbonate shelf margin or reef, (4) carbonate sand flats, (5) carbonate barrier islands, (6) lagoon, and (7) coastal playas and supratidal salt flats (sabkhas). Over a half century of exploration drilling has shown that hydrocarbons in the Permian rocks of the Permian basin have accumulated at the updip contact of the lagoonal dolomites and clastics with the coastal evaporites, and in the basinal channel-fill clastics. The shelf marginal (reef) facies contain cavernous porosity, but commonly are water saturated. These facies relationships and hydrocarbon occurrences provide an exploration model with which to explore and rank hydrocarbon potential in other carbonate provinces.

Internal Geometry, Seismic Facies, and Petroleum Potential of Canyons and Inner Fan Channels of the Indus Submarine Fan

Abstract: The Indus Fan, the second largest submarine fan in the world, covers 1,250,000 km2 (500,000 mi2) and contains sediment more than 7 km (23,000 ft) thick. Multichannel (24-fold) CDP seismic data provide the bases for evaluating the Indus Fan and consist of four seismic facies. Of these, only the high-amplitude, discontinuous (H-D) facies is thought to contain reservoir-quality sandstones. The H-D facies is confined to the axes of leveed channels. Canyon-channel systems that fed the fan in the past can be divided into three zones. The degradational zone is composed of an erosional canyon complex filled by prodelta mud. The transitional zone, located near the canyon mouth, consists of superimposed channels that initially were erosional but eventually aggraded and developed levees. The headward termination of the H-D facies occurs in this zone. The aggradational zone consists of superimposed leveed channels confined solely by their own levees. The H-D facies forms extensive interconnected bodies several kilometers (about 2 mi) wide and 100 m (330 ft) thick in aggradational channels. The proximal termination of the H-D facies near canyon mouths implies the presence of reservoir-quality sandstone surrounded by source/seal mudstone in the transitional zone. This stratigraphic trapping geometry and structural leads may represent a vast, untapped petroleum province.

Hydrocarbon Prospects of Southern Indus Basin, Pakistan

Abstract: The Southern Indus basin extends approximately between lat. 23° and 28°31^primeN, and from long. 66°E to the eastern boundary of Pakistan. Of the 55 exploratory wells drilled (1955-1984), 27 were based on results of multifold seismic surveys. Five commercial oil discoveries and one gas discovery in Cretaceous sands, three gas discoveries in Paleocene limestone or sandstone, and one gas-condensate discovery from lower Eocene limestone prove that hydrocarbons are present. The main hydrocarbon fairways are Mesozoic tilted fault blocks, Tertiary reefal banks, and drape and compressional anticlines. Older reservoirs are accessible toward the east and northeast, and younger mature source rocks are to the west, including offshore, of the Badin block oil field area The Indus offshore basin reflects sedimentation associated with Mesozoic rifting of the Pakistan-Indian margin, superimposed by a terrigenous clastic depositional system comprised of deltas, shelves, and deep-sea fans of the Indus River.

Geologic Framework of Italian Petroleum Resources

Abstract: Sedimentary sequences in Italy were deposited mostly on the African continental margin and in the contiguous ocean generated by Jurassic spreading. Triassic to Lower Cretaceous carbonates reflect the extensional tectonics that preceded and accompanied oceanic opening. Younger clastics formed in response to location and elevation of the source areas and to the tectonically controlled bathymetry of the basins. The major structural units of Italy are (1) island of Sardinia, a fragment of the European continental margin that escaped Alpine compressive tectonics; (2) Tyrrhenian Sea, a Miocene-Pliocene extensional area with oceanic crust; (3) southern Alps fold-thrust belt; (4) Apennine fold-thrust belt, with regional nappes; (5) foredeep; and (6) foreland. Gas reserves in Ital are primarily in Pliocene sand reservoirs of the external (outer) Apennines and the foredeep. The gas is biogenic, and the source is immature organic matter in coeval shales. The major part of the oil and part of the gas are thermogenic, derived mainly from black shales deposited in Middle Triassic, Upper Triassic, and lower Liassic basins. Petroleum generation began during the Mesozoic in the deepest parts of these basins, and heavy oil migrated into the adjacent Mesozoic carbonate reservoirs. Condensate and wet gas originated in the areas of major Cenozoic subsidence and migrated into Tertiary clastic reservoirs where tectonism was more intense. A minor part of the oil in Tertiary sand reservoirs may have been sourced by organic matter in shales of Miocene flysch. In 1984, gas and oil production in Italy supplied about 10% of the national energy demand. Although petroleum exploration has been heavy since 1950, plays with good potential still exist. They commonly depend on definition of rather deep structures, both onshore and offshore.

The Framework of Hydrocarbon Generation and Migration, Gulf of Mexico Continental Slope

Abstract: The occurrence of large volumes of crude oil and thermogenic gas in Plio-Pleistocene reservoirs and Holocene seeps of the Gulf of Mexico slope argues that the process of hydrocarbon generation and migration continues at the present time. Calculated thermal maturity models based on deep seismic stratigraphy indicate that Cretaceous and possibly Early Tertiary sediments are presently within the thermal maturity range for generation and expulsion of crude oil. The Cretaceous and Early Tertiary sediments are suggested as possible source rocks because younger sediments are thermally immature for crude oil generation, and older sediments are thermally overmature for crude oil preservation. The calculated thermal maturity profile for the slope indicates that some generation of crude oil could occur as shallow as 6 km, and that liquid hydrocarbons could be preserved as deep as 9 km. Thermogenic gas is stable at even greater depths. Migration with a strong vertical component must be invoked to explain thermogenic hydrocarbons in shallow reservoirs and seeps of the slope. The great depth at which liquid hydrocarbons and dry gas can be preserved in reservoirs of the Gulf of Mexico Salt Basin indicates that huge volumes of prospective section remain essentially unexplored.

Dry sump crankcase

Abstract: An engine oil pan of the dry sump type is divided into inner and outer parts by a funnel-like baffle with a hole in the bottom, the hole being of a controlled vertical height, the outer part being an oil reservoir connected to the engine suction side of the engine positive crankcase ventilating (PCV) system, the inner part receiving the oil therein from the various engine parts and being connected to the fresh air inlet side of the PCV system, thereby, during normal engine operation, establishing a constant pressure differential across the baffle to force oil collected in the inner part through the hole into the outer part, the oil level in the inner part stabilizing at the level of the hole in the baffle, the oil in the outer part stabilizing at a level dependent upon the total quantity of oil in the system and the volume of the reservoir, thereby removing standing oil from the vicinity of the moving parts in the crankcase which reduces friction and aeration of the oil and yet provides an adequate supply of oil to the engine oil pump.

Porosity Reduction in Sandstone by Quartz Overgrowth

Abstract: A mathematical model for predicting porosity histories due to quartz overgrowth in quartz-rich sandstone reservoirs has been developed. The model neglects secondary dissolution porosity and other diagenetic processes such as compaction and precipitation of carbonate and clay minerals. Nevertheless, the model is straightforward and easy to use to calculate porosity. The calculated porosity corresponds to measured porosity of simple quartz-cemented sandstones in 27 wells in North and South America. The model is based on fluid flow through initially porous, unlithified sands in which the fluid phase is saturated with Si(OH)4 and is always in equilibrium with quartz. As the continuously circulating fluid migrates updip toward the basin edge, it cools, and quartz precipitates into the pore spaces causing a loss of porosity. Basinal fluid velocities may be calculated assuming (1) thermal convection and (2) hydrostatic pressure due to recharge at the edge of the basin. Porosity diagrams relating porosity to geothermal gradient, burial rate, and depth of burial are compared to thermal maturation models of source rocks, fluid flow history, and grain-size distribution. The rate of porosity reduction depends on the following variables in decreasing order of significance: buria rate, age, initial porosity, basin size (dip angle), fluid dynamics, initial permeability, and geothermal gradient.

Reservoir Facies Architecture of Microtidal Barrier Systems

Abstract: Sandstone reservoirs deposited in microtidal barrier systems contain large oil and gas reserves in several Gulf Coast basin plays. Three representative Frio Sandstone reservoirs in West Ranch field show that barrier-island sand bodies are complex mosaics of barrier-core, inlet-fill, flood-tidal-delta, washover-fan, barrier-flat, and shoreface facies. The proportions of these facies differ within progradational, aggradational, and transgressive barrier sand bodies. The 41-A reservoir is a progradational barrier sand body. The most important producing facies include the barrier core and crosscutting inlet fill. Permeability and distributions of irreducible water saturation reveal depositional patterns and subdivisions of the sand body into numerous facies-controlled compartments. Both original hydrocarbon saturation and irregularities in water encroachment show that the facies compartments locally affect fluid movement within the reservoir. The Greta reservoir is an aggradational barrier complex. This massive sand body consists of intermixed barrier-core and inlet-fill units. Prominent resistivity compartments are dip oriented, indicating the importance of inlet development during barrier aggradation. Despite the uniform appearance of the Greta reservoir, water encroachment has been irregular. The Glasscock reservoir is characterized by comparatively low permeability and is an atypically thin and discontinuous Frio reservoir. It is interpreted to be a transgressive barrier deposit that consists mainly of large washover-fan and associated barrier-flat sands. Hydrocarbon saturation, drainage, and injection response all reflect the facies geometry typical of a transgressive barrier complex.

Diagenesis of Sandstone Reservoirs of Pattani Basin, Gulf of Thailand

Abstract: Miocene sandstones from gas fields in the Gulf of Thailand's Pattani basin provide an example of rapid decline in porosity and permeability with increasing burial depth. This decline results from rapid burial diagenesis that is related to very high geothermal gradients in the basin. Porosity loss with depth in these subquartzose sandstones results from mechanical compaction and from progressive cementation by quartz overgrowths, kaolinite, and illite. Quartz overgrowths increase with depth, indicating continuous or episodic silica cementation. Kaolinite occurs as a pore-filling cement and is abundant between the depths of 1,980 and 3,050 m (6,500 and 10,000 ft). Minor cements include calcite, ankerite, mixed-layer illite-smectite, siderite, pyrite, chlorite, and barite. > The best porosity and permeability in Pattani basin reservoirs are generally associated with large intergranular pores in sandstones between 915 and 1,980 m (3,000 and 6,500 ft). At greater depths most interparticle pores have been occluded, and porosity is mainly secondary in origin. Skeletonized feldspars indicate progressive dissolution with increasing burial depth. In low-permeability sandstones from deeper zones (2,285-3,050 m or 7,500-10,000 ft), porosity is mainly restricted to dissolution voids within detrital feldspars. These secondary pores are usually partly filled by authigenic kaolinite and illite, and their pore apertures are generally smaller (1-15 µm) than intergranular pore apertures (10-75 µm). However, favorable reservoir properties may occur locally at de th where large feldspars have been leached from coarse-grained sandstones.

Geology of Tight Gas Reservoirs

Abstract: Tight gas reservoirs occur in low-permeability, gas-bearing formations that are present to some extent in all gas-producing basins worldwide. This is the first volume to bring together data on tight reservoirs for a variety of basins and different geologic settings. The papers in this volume discuss characteristics of some of the most significant tight gas areas in the United States; however, these data are equally applicable to many other recognized and unrecognized tight gas provinces in other nations. In general, tight reservoirs in the United States are grouped into tight gas sandstones and eastern Devonian shales. The Devonian shale sequences are dominantly marine shale but include some siltstone and sandstone. Tight gas sandstone formations of other than Devonian age are present throughout the United States and consist primarily of fluvial and marine sandstones and siltstones. In addition, gas also occurs in low-permeability marine carbonate reservoirs. The 14 papers in this volume cover such topics as: coal-bed methane and tight gas sands interrelationships; gas-bearing shales in the Appalachian basin; exploration and development of hydrocarbons from low-permeability chalks; and geologic characterization of low-permeability gas reservoirs.

Applied open-hole log analysis

Abstract: The Petroleum Reservoir. The Basics of Resistivity. Spontaneous Potential. Resistivity Logs. Sonic Logs. Analyzing the Log. Nuclear Logs. Resistivity-Porosity Crossplots. Porosity Crossplots. Mineral Crossplots. Permeability. New Technology. Shaly Sand Analysis. Appendixes.

Diagenetic Traps in Sandstones

Abstract: Diagenesis may be an important agent in trapping hydrocarbons in sandstones by formation of reservoirs or seals. Reservoirs are formed by the creation of secondary porosity during burial. Seals are formed by heavy cementation, which may allow sandstones to retain large hydrocarbon columns. Formation of a diagenetic trap requires that parts of the sandstone unit react differently from each other during burial. This can be caused by differences in (1) detrital mineralogy--resulting from grain size or depositional environment controls; (2) early diagenetic mineralogy--largely depositional environment controlled; (3) burial history--structural movement induced; and (4) fluid content--hydrocarbon or water saturation. Each of these factors can lead to differences in porosity and permeability of the sandstone sufficient to form reservoirs and seals. In the correct configuration, diagenetic traps may be formed. Basin-center gas accumulations result from diagenetic trapping in some instances.

Determination of gas-condensate relative permeability on whole cores under reservoir conditions

Abstract: Rock samples from a Middle East carbonate retrograde condensate gas field were studied to determine their relative permeability to gas and condensate curves. The authors emphasized the determination of condensate minimum flowing saturation-or critical condensate saturation-and the reduction of permeability to gas in the presence of immobile condensate saturation. A ternary pseudoreservoir fluid of methane/pentane/nonane made it possible to work in simulated reservoir conditions with a greater flexibility for experimental procedures. The initial water saturation equaling that in the reservoir was restored. The results of the gas-condensate indicate that the critical condensate saturations are high (the average value is 36% PV) and that the reduction of permeability to gas is higher than for a standard gas/oil system. Also presented are the details of the experimental procedures, the fluid characteristics, the results, and a discussion.

Hydrodynamic Conditions of Hydrocarbon Accumulation Exemplified by the Carboniferous Formation in the Lublin Synclinorium, Poland

Abstract: Groundwater movement in a selected aquifer of a sedimentary basin in the Lublin synclinorium is considered on the basis of rock and fluid data, and conditions of migration and accumulation of hydrocarbons are presented. The problem of groundwater movement is solved analytically, taking into consideration variable density of water and variable permeability of rocks. A modified theory is advanced to define more precisely the position of potential oil and gas traps. The theory introduced here is more universal than Hubbert's theory because it accepts both the variability of the oil, gas, and water density (static effect) and the groundwater motion (dynamic effect). The suggested method of determining the positions of potential hydrodynamic petroleum traps is comparatively simple to apply and gives good results in regions with high hydraulic gradients and high variablility of salinity and hydrocarbon densities.

Shuaiba reservoir geological study, Yibal field, Oman

Abstract: The Yibal oil field in west central Oman is a large dome created by deep-seated salt movement. The maximum oil column is 370 ft (112.8 m) and the productive area is about 4.3 x 6.2 mile (7 x 10 km). The structure is complicated by extensive tensional faulting. The main oil accumulation is in the Shuaiba chalk overlain disconformably by the Nahr Umr shale. The Shuaiba reservoir is in pressure communication with the underlying Kharaib formation. It is speculated that early accumulation of oil played a major role in preserving the high porosity and greater crestal reservoir thickness by inhibiting diagenetic processes. This field study provided the reservoir simulation engineer with a viable geological and petrophysical model of the Shuaiba reservoir to aid in understanding observed phenomena.

Relationship of Unconformities, Tectonics, and Sea Level Changes in the Cretaceous of the Western Interior, United States: Part III. Middle Rocky Mountains

Abstract: Intrabasin tectonics and sea level changes influenced patterns of deposition and geographic distribution of major unconformities within the Cretaceous of the Western Interior. Nine major regional to near regional unconformities have been identified. Previous workers have related five of these unconformities to sea level changes and to well known regressive-transgressive cycles. The origin of the other four unconformities may be related either to tectonic movement or sea level changes. The approximate dates for unconformities are estimated as follows (formations involved are in parentheses): (1) late Neocomian to early Aptian, 112 m.y. (base lower Mannville, Lakota, Lytle); (2) late Aptian-early Albian, ~100 m.y. (upper Mannville, Fall River, Plainview); (3) Albian, ~97 m.y. (Viking, Muddy, Newcastle, or J Sandstone); (4) early Cenomanian, ~95 m.y. (lower Frontier-Peay, and D); (5) Turonian, ~90 m.y. (base upper Frontier or upper Carlile); (6) Coniacian, ~89 m.y. (base Niobrara or equivalents); (7) early Santonian, ~80 m.y. (Eagle, lower Pierre and upper Niobrara); (8) late Campanian, ~73 m.y. (mid-Mesaverde Ericson, base Teapot); (9) late Maestrichtian, ~66 m.y. (top Lance or equivalents). Variations in the accuracy of the dating are probably within 1 m.y. because f problems in accurately defining the biostratigraphic level of the breaks and in the precision of radiometric dates. The unconformities are grouped into three types: those completely within nonmarine strata such as at the base and top of the Cretaceous, those involving both marine and nonmarine strata, and those within marine strata, as currently mapped. Three examples are described as typical of the unconformities, all thought to be related primarily to drops in sea level, but with minor influence by tectonic movement. One is the ~97 m.y. unconformity, with which the petroleum-producing J and Muddy Sandstone is related. A second is ~90 m.y. unconformity which is recognized by relationships within the shelf, slope, and basin deposits of the Greenhorn, Carlile, and Frontier formations. The third is the ~80 m.y. unconformity within the basin and shoreline regression associated with the upper Niobrara, lower Pierre, Eagle, and Shannon formations. Several billion barrels of oil were found in sandstones associated with unconformities in the Cretaceous of the Rocky Mountain region. Future stratigraphic trap exploration is guided by a knowledge of tectonic influence on sedimentation during sea level changes and how these factors control distribution of source rock, migration patterns, reservoir rock, and seal.

Process for oil recovery from subterranean reservoir rock formations

Abstract: Oil is extracted from subterranean reservoir rock formations by injection of a solution or dispersion of a carboxymethylated oxalkylate R--(OC 3 H 6 ) m (OC 2 H 4 ) n OCH 2 COOM in admixture with a more hydrophobic tenside, for example a mono- or dialkylbenzenesulfonate, a petroleum sulfonate or an alkanesulfonate. The process is especially suited for reservoirs governed by strong temperature fluctuations or by a temperature gradient.

Geologic Characterization of Low-Permeability Gas Reservoirs in Selected Wells, Greater Green River Basin, Wyoming, Colorado, and Utah

Abstract: Large gas resources occur in low-permeability Upper Cretaceous and lower Tertiary reservoirs in the Greater Green River basin of Wyoming, Colorado, and Utah. Most of the gas-bearing reservoirs are overpressured, beginning at depths of 8,000 to 11,500 ft (2,440 to 3,500 m). The reservoirs are typically lenticular nonmarine and marginal marine sandstones. In situ permeabilities to gas are generally less than 0.1 millidarcy (md) and porosity ranges from 3 to 12%. Secondary porosity, after dissolution of framework grains and cements, is the dominant type of porosity. Gas accumulations are characterized by the presence of updip water-bearing reservoirs and downdip gas-bearing reservoirs. The top of these overpressured gas-bearing reservoirs cuts across structural and stratigra hic boundaries and is not associated with any particular lithologic unit. These overpressured accumulations are the result of gas accumulating at rates greater than it is depleted. Data from reference wells indicate that in the deeper parts of the basin the relatively closed nature of this system imposes severe restrictions on the ability of gas to migrate appreciable distances from the interbedded source rocks. Consequently, the temporal relationships of hydrocarbon generation and migration with respect to the development of structural and stratigraphic traps is not as important in these unconventional reservoirs as in more conventional reservoirs. The more important factors related to gas generation and occurrence are source rock (quantity and quality), organic maturation, thermal history, formation pressure, and porosity and permeability variations.

Stratigraphic Traps for Petroleum in Wind-Laid Rocks

Abstract: Three major kinds of stratigraphic traps for petroleum exist in wind-deposited rocks: geomorphic, diagenetic, and system-boundary traps. Geomorphic petroleum traps are those in which oil is trapped in association with preserved topographic relief on eolian sands. The preserved relief may be inherited from the original dune field, modified by reworking, or created by erosion of dune sandstones prior to burial by the next layer of sediments. Diagenetic traps for petroleum are those in which oil is trapped by lateral changes in porosity and permeability within the wind-laid rocks. Usually, oil is trapped against cemented zones, which may be selective or nonselective of depositional facies. The propensity of eolian deposits to have diagenetic traps may be due to early cementation, reflecting the common association of desert dunes and evaporites. Traps for petroleum may also be created by decementation--typically the dissolution of early halite, gypsum, or anhydrite. System-boundary traps for petroleum are those in which oil is trapped at the updip depositional edge of the eolian-system deposits, where they intertongue with impermeable sediments of a different depositional environment. System-boundary traps can be sharp or diffuse. Sharp system-boundary traps can create or help create large single pools, such as the 1.6 billion bbl pool at Rangely oil field, Colorado. Diffuse system-boundary traps may contain as much oil as sharp system-boundary traps, but the oil is spread over a much wider area in a multitude of smaller pools, as in the Minnelusa Formation of northeast Wyoming.

Porosity Distribution in San Andres Formation (Permian), Cochran and Hockley Counties, Texas

Abstract: The lower San Andres Formation in Cochran and Hockley Counties, Texas, is one of the most prolific hydrocarbon-bearing horizons of the Permian basin. It is a cyclic sequence of shallow-water carbonates and evaporites which prograded across the Northwest shelf toward the Midland and Delaware basins. San Andres production results from the vertical stacking of porous dolomite reservoirs. Stratigraphic trapping of hydrocarbons results from porosity pinch-outs defined by the degree of dolomitization and anhydrite plugging, both vertically near the top of depositional cycles, and on a regional scale. Stratigraphic trapping, combined with subtle structural nosing and changes in dip, define the limits of production. Reservoir zones are regionally correlatable and mappable. Major roductive trends pinch out northward onto the Matador arch, defining this feature as a major influence on San Andres deposition and production.

Potential Basin-Centered Gas Accumulation in Cretaceous Trinidad Sandstone, Raton Basin, Colorado

Abstract: The Raton basin of southern Colorado is geologically analogous to other Rocky Mountain Laramide basins that contain areally and volumetrically large accumulations of natural gas reservoired in tight Cretaceous and Tertiary sandstones and located in the deeper parts of the basins. Such basin-centered gas accumulations are recognized as a class distinct from conventional structural or stratigraphic traps. Based on geologic analogy, specific detailed geologic mapping, observed gas shows, and bore-hole log analysis, a basin-centered gas accumulation is postulated to exist in the deeper part of the Raton basin in the Trinidad Sandstone.

Geochemical study on genesis of natural gases accumulated in deep volcaniclastic rocks.

Abstract: Chemical and isotopic analyses were applied to characterize genesis of natural gases commercially produced in north-east Japan, so called “Green Tuff” region. Concentrations of He and N2, isotopic ratios of 3He/4He and 4He/20Ne, δ13C values of CH4 showed positive correlations with stratigraphy of gas reservoirs. Especially isotopic values of He included in the deepest gases from volcaniclastic rocks in Nanatani and Nishikurosawa Formations were almost equivalent to those of volcanic fumaroles in the Japanese Islands, suggesting high contribution of mantle materials.On the other hand the genetic diagram of hydrocarbon compositions versus δ13C values of methane attributed hydrocarbon compounds exactly to pyrolysis products of organic matters in sedimentary rocks regardless of their reservoir rock types.No more than 1% of methane seems to be derived from upper mantle, whose contribution may be estimated by comparing CH4/3He values of Green Tuff gases with those of hydrothermal fluids according to studies of EPR.

Permeability Variation in a Sandstone Barrier Island-Tidal Channel-Tidal Delta Complex, Ferron Sandstone (Lower Cretaceous), Central Utah

Abstract: This paper describes a study to determine how permeability varies spatially in outcrops of an ancient barrier island-tidal channel-tidal delta complex. This type of information is useful for developing models of between-well reservoir permeability heterogeneity for application where data are not available. Fifteen outcrop exposures representing different vertical sections of the complex were examined to determine the lithofacies present and their distribution. Horizontal cores approximately six in. long and one in. in diameter were taken at selected locations for permeability measurements. These observations and measurements give the following picture of permeability structure in the sediments of this particular complex. Permeability heterogeneity occurs on several size scales. On the largest scale, crossbedded, burrowed, rippled, and shaly lithofacies are distinguished for characterizing gross permeability layering. These permeability units are continuous over distances of at least 500 to 1000 ft in the seaward direction and probably are continuous over much greater distances in the along-shore direction. Some lithofacies did not define independent permeability units, however, and had to be combined with vertically adjacent facies to form a unit. On an intermediate scale, permeability sublayers on the order of 2 to 4 ft thick occur within some of the units. The lateral extent ofmore » these sublayers was not determined. On a small scale within the sublayers, permeability variation appears to be random for samples that are separated by at least 6 in., the minimum sample separation investigated. Estimates are given in the paper for the magnitude of permeability contrast between permeability units, the lateral variation of mean permeability within a unit, and the permeability contrast between sublayers within a unit.« less

Wattenberg Field, Denver Basin, Colorado

Abstract: The most important mineral resource activity in Colorado during the past decade has been the discovery and development of the Wattenberg and adjacent petroleum fields. Located north of Denver across the axis of the Denver basin, the Wattenberg is estimated to have reserves of 1.3 trillion cubic feet (tcf) in the tight J (Muddy) Sandstone (delta front) reservoir over an area of 600,000 acres at depths of 7,600 to 8,400 ft (2,310 to 2,560 m). Net pay thickness varies from 10 to 50 ft (3 to 15 m), porosity ranges from 8 to 12%, and permeability varies from 0.05 to 0.005 millidarcys (md) (Matuszczak, 1973, 1976). Drilling for J gas has resulted in multiple pays in overlying strata. The Spindle field, situated in the southwest portion of the Wattenberg field, produces from two marine-bar complexes (Hygiene and Terry) in the middle portion of the Pierre Shale. In 1981 and 1982, the Codell Sandstone, approximately 500 ft (152 m) stratigraphically above the J, was developed as a new producing horizon of oil and gas. More than 100 discoveries have been made within and marginal to the outlined Wattenberg field area. The Codell is a tight bioturbated marine-shelf sandstone generally without a central-bar facies. Net pay thickness ranges from 3 to 25 ft (0.9 to 7.6 m). Porosities determined from logs range from 8 to 24%, but the average core porosity is from 10 to 12% and permeabilities are less than .5 md. Because of rapid decline in production and economic uncertainties, potential reserves from the Codell are unknown. All petroleum accumulations in the Wattenberg area are regarded as stratigraphic traps, although unconformities and paleostructure have played a subtle but detectable role. Variation in thickness and reservoir quality is related to original environmental facies and paleostructure that locally influenced unconformities, fracturing, and diagenesis.

Lower Tuscaloosa Fluvial Channel Styles at Liberty Field, Amite County, Mississippi

Abstract: Liberty Field is located within the active up-dip Tuscaloosa trend of southwestern Mississippi and east central Louisiana. The Lower Tuscaloosa is composed of siliciclastic sediments derived from the Ouachita Orogenic Belt. These sediments were deposited by rivers which aggraded alluvial/deltaic plains and prograded moderate-size deltas into a shallow, rising sea. Much of the remaining undiscovered reserves within this mature oil play is believed to be present in small-to-medium-sized stratigraphic traps similar in size and style of occurrence to Liberty Field (OOIP of 7 million barrels of oil (MMBO)). Oil at Liberty Field is stratigraphically trapped within the upper two Lower Tuscaloosa sandstones denoted, in descending stratigraphic order, as the "A" and "B" sandstones. Deposited during a transgressive period, these fluvial channel sands mark the passage from continental deposits into the marine shales of the Middle Tuscaloosa. Seismic sand mapping in conjunction with wireline logs from 30 wells and data from 15 conventional cores characterize the vertical succession of channel styles. The A and B reservoir sandstones are medium-to-fine-grained, sublithic sands. Porosities range from 20 to 30 percent whereas permeabilities range between 35 to 800 millidarcies (md). Depositionally, the B sandstone represents a multi-storied, composite point bar and channel deposit. This sand, encased in floodplain silts and shales, was deposited along a low gradient, high sinuosity meander belt having a northwest-southeast trend. Individual channels range from 30 to 35 feet thick, whereas the maximum composite meander belt thickness is 55 feet. In contrast, the overlying A sandstone represents a simple single-storied point bar and channel deposit. Encased in shales containing a restricted marine fauna, this sand was deposited along high sinuosity distributary channel similarly trending northwest-southeast. Maximum channel thickness is 28 feet which commonly is marine reworked in the upper few feet. Meander belt width for both sands varies from 2,500 to 5,000 feet. Gentle structural setting (regional dip of 1°), channel style and orientation all influence hydrocarbon entrapment.

Stratigraphic Aspects of Petroleum Resource Assessment

Abstract: Four major factors control petroleum richness of a region: source rock, reservoir rock, seal, and trap. Assessment of undiscovered resources of oil and gas in poorly known regions should be based on comparative analysis of these factors in a forecast region and in a well-explored analog area. Three of these factors mainly reflect stratigraphic, rather than tectonic, conditions, and the fourth, the trap factor, includes both stratigraphic and tectonic aspects. The predominance of stratigraphic information in the factors indicates that the main unit used for petroleum resource assessment done by comparative geologic analysis should be a stratigraphic unit. Such a proposed unit, which is called an independent petroliferous system (IPS), is understood here as a body of rocks eparated from surrounding rocks by regional barriers to lateral and vertical migration of fluids, including oil and gas. Stratigraphically, an IPS is essentially homogeneous. It includes source rocks, reservoir rocks, traps, and a regional seal, and thus, it is a suitable unit for comparative analysis of the factors and petroleum genetic studies. For oil and gas resource assessment in poorly known regions, an IPS has certain advantages over a basin or play as an assessment unit. The concept of an IPS can also be used in statistical methods of resource appraisal and can increase reliability of these results.