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Showing papers on "Petroleum reservoir published in 1982"


Book
01 Apr 1982
TL;DR: In this paper, the authors define the basic physical parameters and indicate procedures for their evaluation which may be used further in the description of fractured reservoirs, and examine the results obtained by direct measurements on rock samples and indirect measurements from various logging results.
Abstract: In the modem language of reservoir engineering by reservoir description is understood the totality of basic local information concerning the reservoir rock and fluids which by various procedures are extrapolated over the entire reservoir. Fracture detection, evaluation and processing is another essential step in the process of fractured reservoir description. In chapter 2, all parameters related to fracture density and fracture intensity, together with various procedures of data processing are discussed in detail. After a number of field examples, developed in Chap. 3, the main objective remains the quantitative evaluation of physical properties. This is done in Chap. 4, where the evaluation of fractures porosity and permeability, their correlation and the equivalent ideal geometrical models versus those parameters are discussed in great detail. Special rock properties such as capillary pressure and relative permeability are reexamined in the light of a double-porosity reservoir rock. In order to complete the results obtained by direct measurements on rock samples, Chap. 5 examines fracturing through indirect measurements from various logging results. The entire material contained in these five chapters defines the basic physical parameters and indicates procedures for their evaluation which may be used further in the description of fractured reservoirs.

436 citations


Journal ArticleDOI
TL;DR: The authors used paraffin indices, stable carbon and hydrogen isotope contents, pristane to nC17 ratios, and diterpenoid biologic markers to assess the level of maturity of the hydrocarbons in the reservoir.
Abstract: Petroleum has been found in Canadian frontier basins in reservoirs which have undergone low levels of thermal alteration (vitrinite reflectance <=0.6%Ro). Paraffin indices, stable carbon and hydrogen isotope contents, pristane to nC17 ratios, and diterpenoid biologic markers have been used to assess the level of maturity of the hydrocarbons in the reservoir independently of the level of maturity of the reservoir itself and of the surrounding shale units. In the Tertiary of the Beaufort-Mackenzie basin, naphthenic oils and condensates have been generated from terrestrially derived organic matter in source rocks juxtaposed with the reservoir at reflectance levels of 0.4 to 0.6%Ro. However, condensates discovered in reservoirs which are th rmally immature on the Labrador Shelf have undergone extensive vertical migration and can be classed as conventional mature to overmature condensates. Hydrocarbons discovered in the Lower Cretaceous of the Beaufort-Mackenzie basin and also those of the Scotian Shelf are more or less in place in that they are at a level of thermal alteration about equivalent to that of the reservoirs in which they are trapped. The source for the early oils and condensates is considered to be resinite occurring dispersed in coal fragments. The proportion of resinite, liptinite, and vitrinite in the organic matter of terrestrial source rocks strongly controls both the level of thermal alteration necessary for the section to function as an effective source rock and the ultimate product (gas, oil, or condensate) which will be generated.

219 citations


Journal ArticleDOI
K.J. Weber1
TL;DR: In this article, the state of the art of deriving detailed permeability-distribution models on the basis of cores, sidewall samples, and logs is summarized and compared.
Abstract: This study summarizes the state of the art of deriving detailed permeability-distribution models on the basis of cores, sidewall samples, and logs. Reservoir heterogeneities such as clay drapes and intercalations, cross-bedding, sand laminations, slumping and burrowing in various major depositional environments are examined. 30 refs.

159 citations


Journal ArticleDOI
TL;DR: In the early Tertiary, the hydrocarbons in Saudi Arabia were derived from two separate source-rock provinces of Cretaceous and Jurassic age (Callovian-Oxfordian).
Abstract: Current hydrocarbon production in Saudi Arabia is from reservoirs of Cretaceous and Jurassic age Geochemical studies of the sediments and oils suggest that the hydrocarbons were derived from two separate source-rock provinces Oil production from the large fields in the southern part of the area is from Jurassic carbonate reservoirs Most of these oils were derived from thermally mature, thinly laminated, organic-rich carbonate rocks of Jurassic age (Callovian-Oxfordian) These source rocks were deposited in an intrashelf basin which is limited to the southern part of the main producing areas Extensive vertical migration of oils originating in these sediments is prevented by superjacent evaporite seals deposited during the Late Jurassic Fields in the northern producing areas appear to have derived their hydrocarbons from a source-rock province on the north Production from Cretaceous clastic and carbonate reservoirs is limited to the northeastern part of the producing areas This distribution may be explained by limitation of thermally mature Cretaceous source rocks to the northeastern areas or by the local lack of subjacent evaporite seals to separate these reservoirs from Jurassic source rocks Thermal maturation studies indicate that the hydrocarbons in Mesozoic reservoirs migrated into the present traps during the early Tertiary

152 citations


Journal ArticleDOI
TL;DR: The Salton Sea Geothermal field is the largest water-dominated geothermal field in the Salton Trough in Southern California as discussed by the authors, and it can be classified into three categories as a function of depth: low-permeability cap rock, upper reservoir rocks consisting of sandstones, siltstones, and shales, and lower reservoir rocks that were extensively altered.

87 citations


Proceedings ArticleDOI
01 Jan 1982
TL;DR: In this article, the presence or absence of an adsorbed layer of petroleum heavy ends can have a significant impact on oil recovery from the reservoir, and the authors discuss its relevance to EOR.
Abstract: The purpose of this paper has been to point out a phenomenon which may exist or may be induced in petroleum reservoirs and discuss its relevance to EOR. The presence or absence of an adsorbed layer of petroleum heavy ends can have a significant impact on oil recovery from the reservoir. Specifically, an adsorbed layer of petroleum heavy ends can stabilize potentially damaging formation clay minerals against dispersion and subsequent migration. Surfactant additive adsorption is reduced when this adsorbed layer is present on clay mineral surfaces. Also rock wettability changes upon adsorption, but this wettability change may be less important to oil recovery than the stabilization of the clay minerals. 5 refs.

74 citations


Journal ArticleDOI
TL;DR: In this article, it is argued that the Kazhdumi source rock was not buried to the depth required for hydrocarbon generation until the Eocene, and that no significant oil expulsion took place until the Miocene.
Abstract: Sixty-three orogenically controlled oil and gas fields have been discovered in the Zagros sector of southwest Iran since the turn of the present century. Most of the fields are giant, multi-reservoir accumulations producing from fractured carbonate pay zones ranging in age from Permo-Triassic to Oligo-Miocene. The most prolific oil-producing zones are the Asmari Formation (Oligo-Miocene) and the Bangestan Group (Upper Cretaceous). The available geochemical evidence indicates that the major source of the oil is the underlying Lower Cretaceous (Albian) Kazhdumi Formation. It is argued that, in the main oil-producing area, the Kazhdumi source rock was not buried to the depth required for hydrocarbon generation until the Eocene, and that no significant oil expulsion took place until the Miocene. Entry of oil into the reservoirs is geologically a recent event; it postdates the late Miocene-Holocene Zagros orogeny that resulted in the formation of the present structural traps. It is suggested that the development of growth structures during the Late Cretaceous and Paleogene could have contributed to some hydrocarbon localization prior to the formation of the late Tertiary traps.

74 citations


Journal ArticleDOI
TL;DR: Basement reservoirs are a special type of important oil reservoirs that until recently have generally been neglected as targets for exploration as mentioned in this paper, as they always occur on high or uplifts within the basin, and have been subjected to long periods of weathering and erosion.
Abstract: Basement reservoirs are a special type of important oil reservoirs that until recently have generally been neglected as targets for exploration. Most basement reservoirs occur either on platforms or in intermontane basins. They are rare in foredeep basins. The basement reservoirs always occur on highs or uplifts within the basin, and have been subjected to long periods of weathering and erosion. Younger sediments (presumably source beds) directly overlie basement, providing opportunity for entrapment of oil in the basement rock. Almost all basement reservoirs occur below a regional unconformity. All source beds of basement reservoirs lie above the reservoir rock, but all source beds lying above the reservoir rock do not necessarily form basement reservoirs. Although most source beds lie above an unconformity, some lie below it and form a so-called second crop. Unconformities play an important role in basement reservoirs, as they are the passageway for oil migration, provide conditions for long-distance migration, and connect source and reservoir rocks which may lie on opposite sides of the unconformity and at great distances from each other. The unconformity surface provides evidence that basement rocks have undergone weathering, erosion, solution, and leaching for so long a time that porosity and permeability have increased greatly, and the accumulation of petroleum was facilitated. Oil may accumulate in any igneous, metamorphic, or sedimentary rocks with secondary fissures, dissolved interstices, and caverns, or in sandstone and carbonate rocks with primary porosity. Carbonates form the best basement reservoirs because, being hard and brittle, they not only develop secondary fissures, but are readily dissolved by ground water so that original pores are enlarged and new porosity produced. Basement reservoirs are characterized by thick reservoir rocks. Porosity and permeability are irregular. Production from basement reservoirs is usually high and reserves are large.

59 citations


Book ChapterDOI
TL;DR: In this article, the authors find evidence that the sedimentary growth of bioherms was localized over gentle, basement-controlled paleostructures, which is the key to further exploration in the Paradox basin.
Abstract: Significant quantities of petroleum occur in stratigraphic traps of Devonian, Mississippian, and Pennsylvanian ages in the Paradox basin. Devonian reservoirs are isolated marine sandstone bodies, but the Mississippian and Pennsylvanian traps are biohermal carbonates. Exploration has proven the reservoirs to be elusive and relatively unpredictable, but new realization that these subtle traps are localized on paleostructures has simplified exploration and led to several recent discoveries. The tectonic framework of the Paradox basin was set by the end of the Precambrian, but rejuvenation through the Paleozoic caused repeated vertical movements along basement fractures, sufficient to alter sedimentary facies during Cambrian, Devonian, and Mississippian times. Subsurface data indicate that both major and minor structures at the surface today existed in Middle Pennsylvanian time, and grew throughout Permian time. These elements served to localize Paleozoic reservoir facies by creating shoaling conditions on the paleoseafloor that produced Devonian offshore sandbars, Mississippian crinoid banks, and Middle Pennsylvanian algal bioherms. Erosion and salt movement affected much of the potential for continuous reservoir facies, and today's reservoirs are considered to be randomly distributed stratigraphic traps. However, there is ample evidence to indicate that the sedimentary growth of bioherms was localized over gentle, basement-controlled paleostructures. Whereas the reservoirs are too thin for modern seismic detection, isopach thins of underlying evaporites are evident, indicating paleostructure and the development of algal mounds along the crests and flanks of positive structures. Thus, the mapping of paleostructure, not Laramide structure, is the key to further exploration in this basin.

48 citations


DOI
01 Jan 1982
TL;DR: The Catahoula Formation is one of the major Tertiary progradational wedges of the Texas Gulf Coast basin and has yielded nearly 6 billion bbl of oil and 60 trillion cu ft of gas as discussed by the authors.
Abstract: The Frio Formation is one of the major Tertiary progradational wedges of the Texas Gulf Coast basin and has yielded nearly 6 billion bbl of oil and 60 trillion cu ft of gas. The Frio and its updip equivalent, the Catahoula Formation, consist of deposits of 2 large fluvial and associated deltaic systems. All Frio depositional systems contain economically significant, geologically defined hydrocarbon-producing plays. Volume, production style, and type of hydrocarbon within each of 10 recognized plays reflect source-rock quality and type, differing compaction and pore-fluid-migration history, and reservoir and trap configurations characteristic of each depositional system. Analysis of volumetric, historic, and geologic relationships for production and discovery within each play provides a basis for estimating the undiscovered hydrocarbon resource potential as well as for assigning that potential to specific geographic and stratigraphic subdivisions of the depositional basin. 76 references.

48 citations


Proceedings ArticleDOI
TL;DR: In this article, a method for analyzing interference tests in reservoirs with double porosity behavior is presented; it applies to both naturally fractured reservoirs and multilayered reservoirs with sufficiently high permeability contrast between layers.
Abstract: A systematic approach for analyzing interference tests in reservoirs with double porosity behavior is presented; it applies to both naturally fractured reservoirs and multilayered reservoirs with sufficiently high permeability contrast between layers. Type curves are presented for the pressure response at an observation well, the active well being produced at either constant flow rate or constant pressure. They are derived from two models with the assumptions of pseudo-steady state or transient interporosity flow regime. The distinctive specific features they exhibit are clearly identified and quantitatively related to the model parameters. An interpretation method, based on type curve matching, is proposed: after selection of the most appropriate model, and identification of the successive flow regimes, the double porosity behavior of the reservoir is characterized and pertinent parameters are evaluated: flow conductivity kh, interporosity flow parameter ..lambda.., and storativity (/phi/Vc /SUB t/ )h segregation throughout the reservoir. Actual field examples are discussed to illustrate the method.

Journal ArticleDOI
TL;DR: In this article, a comparison between the observed and predicted alteration mineralogy, calculated from fluid-mineral equilibria relationships, was made using the availability of fluids and drill cuttings from the active hydrothermal system at Roosevelt Hot Springs.

Journal ArticleDOI
TL;DR: In this paper, the static hydrocarbon column downdip from a continuous phase occurrence can be calculated from one well bore if the subsurface oil or gas saturation, capillary properties, hydrocarbon-water interfacial tension, oil density, and water density of the reservoir are known.
Abstract: Hydrocarbons occur in the subsurface in four modes: (1) continuous phase oil or gas, (2) isolated droplets of oil or gas, (3) dissolved hydrocarbons, and (4) associated with kerogenous rocks. All of these modes of occurrence can result in what is described as a subsurface hydrocarbon "show." Each show type has markedly different implications to exploration and must be differentiated as the first step in show interpretation. Only continuous phase occurrences of oil and gas indicate that a trapped and potentially producible accumulation of hydrocarbons has been discovered. Free oil or gas recovery from the formation or subsurface hydrocarbon saturations of greater than 55% indicates a continuous phase occurrence. Continuous phase shows can be interpreted quantitatively. The static hydrocarbon column downdip from a continuous phase occurrence can be calculated from one well bore if the subsurface oil or gas saturation, capillary properties, hydrocarbon-water interfacial tension, oil density, and water density of the reservoir are known. Producing wells are by definition continuous phase oil or gas, and estimates of oil-water or gas-water contacts from normally available exploration data are practical and reasonably accurate based on a documented field study. Continuous phase oil or gas can extend either updip or downdip from a commercial reservoir. These continuous phase shows can also be interpreted quantitatively to determine how large an oil or gas column is required downdip to explain the show. By this method it can be determined whether an exploratory well penetrated the updip waste zone or downdip transition zone of an oil or gas field. Field studies illustrate that quantitative show interpretation of noncommercial shows can provide reliable estimates of the downdip hydrocarbon column. This type of data can be used in a systematic manner to explore for subtle stratigraphic and combination traps.

Journal ArticleDOI
TL;DR: The Geysers reservoir is situated in a 60-80 km-wide right-lateral shear zone associated with the North American-Pacific plate boundary and a small fraction of the shear may be occurring as permanent aseismic creep, which is being converted to stick-slip movement in The Geyser reservoir due to steam production as mentioned in this paper.
Abstract: The Geysers reservoir is situated in a 60–80 km-wide right-lateral shear zone associated with the North American-Pacific plate boundary A small fraction of the shear may be occurring as permanent aseismic creep, which is being converted to stick-slip movement in The Geysers reservoir due to steam production Two mechanisms could be responsible for the induced seismicity: a large (>100 bars) increase in effective rock pressure; and an increase in the coefficient of friction The first mechanism requires that the initial state of the reservoir be predominantly liquid-dominated The second mechanism is a consequence of dehydration of the reservoir causing both the ‘hardening’ of clay and fault gouge, and the precipitation of silica

01 Jan 1982
TL;DR: The Gjoa G-37 well, located on a mid-Eocene wrench-related anticline, penetrated 1300 m of interbedded Paleocene marine shales and alkalic volcanics overlain by 2700 m of Paleocene to Recent shales.
Abstract: Exploration on the continental shelf and slope in the northern Labrador Sea has been carried out by the petroleum industry since 1968. Data acquired include seismic reflection and refraction surveys, magnetic and gravity surveys, vertical seismic profiling and seafloor sampling. In addition, two wells — the Aquitaine et al, Hekja 0-71 and the Esso HB Gjoa G-37 — were recently drilled by industry. Hekja 0-71 was drilled to 3267 m in 1979 and the well was deepened to 4566 m in 1980. The section penetrated is dominantly nearshore to marine sandstones and shales. The lower 1000 m of drilled section consists of alkalic volcanics interbedded with chalky clays and ranges in age from Danian to Early Cretaceous. The gross pay interval between 3210 and 3286 m contains shallow marine to continental fluvial Paleocene sandstones and shales. Porous sandstones comprise 44 m of this interval and tested gas and condensate. The Gjoa G-37 well, located on a mid-Eocene wrench-related anticline, penetrated 1300 m of interbedded Paleocene marine shales and alkalic volcanics overlain by 2700 m of Paleocene to Recent shales and siltstones. Rifting in the northern Labrador Sea began, at the latest, in Early Cretaceous. A transform fault zone dominates all tectonic aspects of the shelf. During the Paleocene, extensive volcanism occurred and wrench-related structures formed. Most rifting ceased by late Eocene to early Oligocene. The sediments deposited are 6000 m thick over large areas and locally, where Cretaceous grabens are present, exceed 8000 m. Some of the sediments contain good reservoir rocks as well as petroleum source resinite, in addition to marine-derived organic matter. The kinds of traps present include extensional as well as wrench-related features and possibly large stratigraphic traps. Reservoirs include possible mid-Eocene and known Paleocene sandstones. In addition, Lower Cretaceous sandstones below the volcanics and lower Paleozoic carbonates and sandstones resting on Precambrian crystallines are anticipated.

01 Sep 1982
TL;DR: The Jurassic-Triassic age Nugget sandstone of southwestern Wyoming Overthrust Belt is a texturally heterogeneous reservoir with anisotropic directional properties which have been inherited from the depositional environment, modified by diagenesis, and finally overprinted by tectonism as discussed by the authors.
Abstract: The Jurassic-Triassic age Nugget sandstone of the southwestern Wyoming Overthrust Belt is a texturally heterogeneous reservoir with anisotropic directional properties which have been inherited from the depositional environment, modified by diagenesis, and finally overprinted by tectonism. Predominantly eolian processes deposited crossbedded and horizontally-bedded, very fine-grained to coarse-grained sand in dunes, interdunes and associated environments. Original reservoir quality has been somewhat modified by compaction, cementation, dissolution, clay mineralization, and precipitation of hydrocarbon resins. Low-permeability, gougefilled and carbonate-filled fractures potentially restrict hydrocarbon distribution and affect producibility; whereas discontinuous, open fractures enhance permeability in some intervals. Contrast in permeability between dune and interdune intervals ranges over four to five orders of magnitude. Dune and interdune deposits are locally correlatable with the aid of core, conventional log, and stratigraphic dipmeter data. Stratigraphic correlations can then be utilized to model the lateral and vertical extent of directional properties in the reservoir.

01 Jan 1982
TL;DR: The Barnett Shale as discussed by the authors is a hard bituminous formation that is easily distinguished in drill cuttings or on electrical and porosity logs, and it is a source of hydrocarbons.
Abstract: The Barnett Shale originated as a normal marine shelf deposit on the southwestern flank of the subsiding Southern Oklahoma aulacogen, probably due to the Middle or Late Mississippian collision of the North American plate with South America and/or North Africa. It is a hard, bituminous formation that is easily distinguished in drill cuttings or on electrical and porosity logs. Subsurface correlations allow the Barnett to be informally subdivided into four or five members which can be traced through most of Jack, Wise, and Montague counties. It unconformably overlies rocks of Early to Middle Ordovician age, and it is in turn — with a few local exceptions — conformably overlain by the shales and limestones of the Marble Falls Formation. The growth of Mississippian pinnacle reefs was initiated with the inundation of North-Central Texas by the warm, shallow Barnett seas. The reef complexes are subdivisible into three constituent facies: the reef core, the reef flanks, and the interreef area. The reef cores are porous enough to serve as stratigraphic traps for oil and gas, and they have yielded excellent production in the northern part of the Fort Worth basin for several decades. The Barnett Shale, though itself unproductive, is believed to be the hydrocarbon source for the reef production.

Book ChapterDOI
01 Jan 1982
TL;DR: Wang et al. as discussed by the authors classified sedimentary basins in east China into two categories: depressions and faulted depressions, in which there are three types of subtle traps--lithologic traps, stratigraphic traps, and paleogeomorphologic traps.
Abstract: With different histories of evolution, the sedimentary basins in east China may mainly be classified into two categories: depressions and faulted depressions, in which there are three types of subtle traps--lithologic traps, stratigraphic traps, and paleogeomorphologic traps Subtle traps in depressions, consisting mainly of lithologic traps like sandstone lenses, are controlled by the zone of discrete distribution of large deltaic sandstone bodies Subtle traps in faulted depressions, consisting mainly of buried-hill traps and lithologic and stratigraphic traps like turbidity sandstones and granular limestones are controlled by the structural pattern of the wedge-shaped depressions and the sedimentary facies

Book
01 May 1982
TL;DR: In this article, the authors address one of the problems in the Basin-porosity in many of the producing formations comes and goes rapidly, and present a model for stratigraphic traps.
Abstract: The Williston Basin contains incredible hydrocarbon-producing formations, but with its subtle structures, identifying potential reservoirs is problematic. This publication addresses one of the problems in the Basin–porosity in many of the producing formations comes and goes rapidly. Chapters addressing this include basic information on stratigraphic traps, both in general and in the Williston in specific; interpretation of carbonate lighology from logs, basic omposition of carbonate rocks; types of porosity in carbonates; major nearsurface diagenetic environments; subsurface diagenesis; dolomite and dolomitazation; and major models for stratigraphic traps.

Book ChapterDOI
01 Jan 1982
TL;DR: The Marmul field lies in the Dhofar province of the Sultanate of Oman as discussed by the authors, and the heavy oil accumulation was discovered in 1956 by DHSA who drilled five wells, but it was not considered commercial and operations were abandoned.
Abstract: The Marmul field lies in the Dhofar province of the Sultanate of Oman. The heavy oil accumulation was discovered in 1956 by Dhofar Cities Services who drilled five wells, but it was not considered commercial and operations were abandoned. Petroleum Development Oman acquired the concession in 1969. Producible oil occurs in Paleozoic clastic rocks overlain unconformably by a Cretaceous sealing shale. Initial appraisal showed the complex nature of the reservoir distribution to be due to its glacial to periglacial environment of deposition and a simple geologic model was conceived. Seismic impedance contrast at the seal's unconformity surface was then used as a predictive tool to differentiate glacial waste zones (tillites) from periglacial reservoirs and as a support for the continuing appraisal and development drilling. The glacial to periglacial geologic model was progressively refined by further development drilling. The appraisal effort based on geologic and seismic impedance models was then pursued toward possible additional younger stacked reservoirs stratigraphically trapped at the periphery of the field. Drilling proved these reservoirs to be separate from the main field and oil bearing. The unraveling of the field's complex trapping mechanisms and the refinement of the geologic models needed for primary development and secondary recovery schemes could only be achieved through an integrated approach by geologists and geophysicists.

01 Jan 1982
TL;DR: Porous facies in Pre-Pennsylvanian, Pennsylvanian and Permian strata are potential hydrocarbon reservoirs as discussed by the authors, and three main exploration targets of pre-Pennsylvania and Wolfcampian age are (1) granitewash sandstones, (2) shelf-margin carbonates, and (3) elongate-delta sandstones.
Abstract: Porous facies in Pre-Pennsylvanian, Pennsylvanian, and Permian strata are potential hydrocarbon reservoirs. Within the pre-Pennsylvanian section, shallow-marine carbonates of both Ordovician (Ellenburger Group) and Mississippian age have sufficient porosity and permeability for hydrocarbon accumulation. Three main exploration targets of Pennsylvanian and Wolfcampian age are (1) granite-wash sandstones, (2) shelf-margin carbonates, and (3) elongate-delta sandstones. Granite wash was deposited in fan deltas adjacent to fault-bounded, basement uplifts around the basin margins. Porous facies are braided-channel, fan-plain, and distal-fan deposits. Porous carbonates developed through time along the different positions of the shelf margins. Organic-rich basinal shales are juxtaposed against the porous shelf-margin facies. High-constructive, elongate-delta deposits in the southeastern part of the basin retain high porosity in bar-finder sandstones. In younger strata, dolomites in the Clear Fork and the San Andres. Porosity in these units apparently pinches out to the north. Both stratigraphic and structural traps occur in the basin. Porosity pinch-outs form the primary stratigraphic traps. Major faults are associated with the Amarillo Uplift; smaller faults have been identified in the deeper parts of the basin. The Palo Duro Basin contains source rocks of sufficient quality to generate hydrocarbons. Pennsylvanian and Wolfcampian shales contain up to 2.4 percent total organic carbonmore » and are fair to very good source rocks. Lipid-rich organic matter occurs primarily in basinal shales. Kerogen color and vitrinite reflectance, which measure thermal maturity, indicate that temperatures were sufficiently high to begin to generate hydrocarbons from lipid-rich organic matter. Average reflectance in Pennsylvanian vitrinite is 0.52%; in Wolfcampian samples the average reflectance is 0.48%. Recent oil discoveries in the Palo Duro Basin confirm that oil was generated.« less

Proceedings ArticleDOI
01 Jan 1982
TL;DR: In this paper, an innovative digital shaly sand evaluation approach is presented, which provides information on total and effective reservoir porosity, total effective fluid distribution based on the Waxman-Smits equation, reservoir productivity, silt volume and volumes, types and distribution modes of clay minerals present in subsurface ford.
Abstract: Discussed in this paper, is an innovative digital shaly sand evaluation approach which provides information on total and effective reservoir porosity, total and effective fluid distribution based on the Waxman-Smits equation, reservoir productivity, silt volume, and volumes, types and distribution modes of clay minerals present in subsurface ford. 52 refs.

Journal ArticleDOI
TL;DR: The water saturation of an oil reservoir is typically 15 to 40% of the pore space and independent of elevation above a level close above the oil/water contact as mentioned in this paper, which is not produced with the oil; it is not in hydraulic continuity.
Abstract: The water saturation of an oil reservoir is typically 15 to 40% of the pore space and independent of elevation above a level close above the oil/water contact. This water is not produced with the oil; it is not in hydraulic continuity. Geometric considerations indicate that it is concentrated in pendular rings separated by immobile films of water adsorbed to solid surfaces of grains and any authigenic minerals present. It is water trapped during accumulation of the oil (and may therefore have a different composition from the water below the oil/water contact). Formation water cannot flow upward through an oil or gas accumulation, nor can bacteria (which require a water substrate) penetrate above the level of irreducible water saturation. Bacterial degradation of a significant oil column and water-washing of oil most likely occur during secondary migration. Oil is separated from some solid surfaces by an immobile film of adsorbed water no thicker than 1 mm--possibly by only a monomolecular layer--and so could be altered in the reservoir by catalysis if authigenic or detrital clay minerals are present.

Proceedings ArticleDOI
Amos Nur1
01 Jan 1982
TL;DR: In this article, a seismic array of receivers and transmitters is used to detect changes in seismic velocities and attenuation in fluid saturated rock samples during steam flooding of heave oil reservoirs.
Abstract: Laboratory measurements of seismic velocities and attenuation in fluid saturated rock samples strongly suggest that detectable changes in these properties are anticipated upon steam flooding of heave oil reservoirs, or during other EOR operations. Such changes could be monitored with seismic array of receivers and transmitters situated around the region of enhanced recovery. The array will yield seismic wave travel times and amplitudes and their temporal and spatial changes. Inverting these measured values, it is possible to determine the distribution of velocities and Q within the reservoir. These distributions can uniquely be interpreted in terms of the distribution of a steam phase in the reservoir, using laboratory determined seismic response of reservoir rock samples.

01 Jan 1982
TL;DR: The most commonly mentioned sources of unconventional natural gas are tight gas formations, coal seams, aquifers, and Devonian shales, however, there are other unconventional sources such as methane hydrates, ultra-deep formations, and abiogenic gas as discussed by the authors.
Abstract: The most-often mentioned sources of unconventional natural gas are tight gas formations, coal seams, aquifers, and Devonian shales. However, there are other unconventional sources such as methane hydrates, ultra-deep formations, and abiogenic gas. The chemical composition of gas from unconventional sources is essentially the same as natural gas from conventional resources which varies with the producing horizons. The major difference between the two is the nature of the reservoir. In unconventional sources the reservoir rock also may be the source bed, the permeability and porosity of the reservoir may be significantly less, the reservoir actually may be an aquifer, and/or the reservoir rock may not be the commonly accepted sandstone or carbonate formation. Gas production from the unconventional resources is technically more difficult, usually more expensive, and less predictable than conventional sources. This study describes the different unconventional natural gas resources. The difficulties in terms of production and the degree of success with producing the resources are discussed. 14 references.


Patent
09 Jun 1982
TL;DR: In this paper, a micellar displacement fluid comprising a hydrocarbon, cosurfactant, brine and two or more different petroleum sulfonates is used to achieve enhanced oil recovery from a subterranean petroleum reservoir.
Abstract: Enhanced oil recovery from a subterranean petroleum reservoir is realized by successively flooding oil-bearing subterranean formations with (1) a micellar displacement fluid comprising a hydrocarbon, cosurfactant, brine and two or more different petroleum sulfonates, (2) a mobility buffer, and (3) an aqueous drive fluid; the oil is recovered from one or more production wells spaced apart from the injection well in the reservoir.

Journal ArticleDOI
TL;DR: Hatter's Pond Field in northern Mobile County, Alabama has produced 11 million barrels of condensate and 43 billion cubic feet of gas since its discovery in 1974 as mentioned in this paper, which is the largest underground gas production in the United States.
Abstract: Hatter's Pond Field in northern Mobile County, Alabama has produced 11 million barrels of condensate and 43 Bcf of gas since its discovery in 1974. Production is from multiple pay zones in the Upper Jurassic Norphlet and Smackover Formations. The trapping mechanism in the field is a highly complex, combination structural and stratigraphic trap involving salt movement in association with normal faulting. The Smackover in the Hatter's Pond Field area is enigmatic for the Smackover in Alabama for two principal reasons. One, the Smackover is very thin (less than 200 feet) in comparison to thicknesses to the northwest and southeast. Secondly, the Smackover does not show the characteristic lower Smackover-upper Smackover lithologic subdivision so apparent throughout south Alabama and the Gulf Coast. These unique features are a product of the field's position on the northwest flank of the Wiggins uplift. Smackover deposition was significantly affected by the uplift which maintained the Hatter's Pond area as a subaerial high, while lower Smackover carbonates were being deposited in the deeper areas of the Mississippi Interior Salt Basin and Conecuh embayment. It was not until near maximum transgression that the seas covered the Hatter's Pond area and deposited shallow-water upper Smackover lithologies. These lithologies were later massively dolomitized by mixing-zone dolomitization during the subsequent Buckner regression. This dolomitization almost completely masked depositional textures, but was largely responsible for the development of reservoir grade porosity in the Hatter's Pond area. Six major lithofacies can be identified in the Smackover in the Hatter's Pond Field: anhydritic mudstone, skeletal-pelodial packstone/grainstone, oolitic grainstone, microcrystalline dolomite, finely-crystalline dolomite, and coarsely-crystalline dolomite. The microcrystalline dolomite is commonly associated with bedded and nodular anhydrites and is interpreted to represent early replacement in a sebkha environment. Both the finely- and coarsely-crystalline dolomites are secondary in nature and represent replacement of low energy skeletal-peloidal packstones and high energy oolitic grainstones respectively. The majority of the reservoir porosity in the Smackover is late stage vuggy and/or moldic and is facies selective and preferential to the coarsely-crystalline dolomite. This porosity, which commonly ranges from 4 to 22% with permeabilities of 2 to over 100 millidarcies, is a product of mesogenetic leaching related to migration of CO2-charged fluids during the early stages of hydrocarbon maturation. The porosity is facies selective to the coarsely-crystalline dolomite since this lithology possessed the greatest porosity and permeability at the time of migration of the CO2-charged solutions. Evidence suggests the oolitic grainstones, which were the precursors of the coarsely-crystalline dolomites, were deposited as a series of linear bars along the flanks of the Wiggins uplift. If this is the case, and more study is needed to document this definitively, the coarsely-crystalline dolomite should occur in elongate mappable trends. Hydrocarbon exploration in this area and all along the flanks of the Wiggins uplift should involve location and mapping of these trends with the greatest success occuring in areas where the trends are superimposed over structural highs produced by faulting and/or salt diapirism.

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TL;DR: In this article, dilute mineral acids were used to liberate additional new organic acids from their nonreactive compounds such as esters, amides, and acid-base complexes present in the crude oil.
Abstract: The process of recovering residual oil from an oil reservoir, by alkaline flooding relies on soap formation by the reaction of the alkali and free long-chain organic acids in the crude oil. In this study, dilute mineral acids were used to liberate additional new organic acids from their nonreactive compounds such as esters, amides, and acid-base complexes present in the crude oil. This was accompanied by an observed enhanced or regenerated interfacial activity of the oil. This acid pretreatment method may be applied to oil reservoirs which have been exhausted by previous alkaline floodings to regenerate activity in the residual oil or to reservoirs never exposed to any alkali contact to give the subsequent alkaline flooding a better first-round recovery. The major technical problem anticipated in applying this process to actual reservoirs is the consumption of acid by th reservoir rock. An analysis was done that showed that sandstone reservoirs with low clay and carbonate content are amenable economically to such an acid treatment. Slug sizes for the acid and water buffer slugs have been estimated using a simple diffusion, convective dispersion model to ensure that the acid and alkaline slugs do not mix.

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TL;DR: In this article, the authors investigated the phenomena occuring during production from and injection into two-phase geothermal systems using numerical simulation and an analytically solvable lumped-parameter reservoir model, using systems with uniform initial conditions as well as systems with steam/water interfaces.
Abstract: This study investigates, for a variety of idealized model reservoirs, the phenomena occuring during production from and injection into two-phase geothermal systems. Using numerical simulation and an analytically solvable lumped-parameter reservoir model, we study systems with uniform initial conditions as well as systems with steam/water interfaces. The main objective is to identify the signature of reservoir characteristics in pressure decline curves for different production and injection strategies. 18 refs.