Showing papers on "Effective porosity published in 1985"

Formation of secondary porosity in sandstones by quartz framework grain dissolution

Abstract: An understanding of the nature and origin of porosity in sandstones is crucial to the evaluation of their potential as hydrocarbon reservoirs. Primary porosity is normally destroyed by cementation, compaction and pressure solution during burial, but it has recently been recognized that significant secondary porosity can develop at depth1–3. This discovery has been called “the most significant advance in the study of clastic diagenesis in the past decade”4. Several genetic types of secondary porosity have been identified ; these include porosity formed by: (1) fracturing; (2) shrinkage; (3) dissolution of sedimentary grains and matrix; (4) dissolution of authigenic cements; and (5) dissolution of authigenic replacive minerals5. Formation of secondary porosity by framework grain dissolution has been thought mainly to involve decomposition of feldspars and lithic grains6,7.We demonstrate here that significant secondary porosity can also develop by dissolution of quartz framework grains if the rocks are exposed to alkaline pore fluids during deep burial and/or uplift.

Eocene and Upper Cretaceous carbonate reservoirs in east-central Tunisia

Abstract: Regionally, well-defined belts of lowest Eocene (Ypresian) Metlaoui carbonates trend northwest-southeast. On the northeast is an open-marine, basinal facies of planktonic foraminiferal micrite and marl. Thick bars of shallow marine nummulitic wackestone, packstone, and grainstone trend northeastward at an angle to the paleoshelf. Lagoonal or supratidaly carbonates are widespread between the shelf deposits and thick evaporites that crop out in intermontane basins. The reservoir is confined largely to nummulitic packstone, and visible effective porosity is best developed between forams in zones filled with sand-size debris where secondary solution-enlargement has occurred. Porosity within nummulite chambers, while abundant, is ineffective, although a few open fractures were observed in cores. This lithology tested oil in 2 recent wildcats and is a commercial reservoir at Sidi El Itayem and Ashtart fields. Distribution of Zebbag carbonates of Late Cretaceous (Turonian) age is more complex. A northwest-southeast-trending platform is bounded on 3 sides by basinal shale and micrite with planktonic forams which grade into a transitional facies of micrite and wackestone that shows some evidence of shallow-water deposition, such as dolomitization, bioclasts, rare ooliths, etc. Predominately back-reef and lagoonal bioclastic wackestones and packstones occur in narrow belts, apparently controlled at least locally by block faulting. Themore » rest of the platform lithology comprises mostly dolomite and dolomitic limestone. The most significant porosity is interparticle (generally solution-enlarged) in foram packstones, but intraparticle porosity in forams and rudists commonly enhances the reservoir. Intercrystalline porosity in dolomitized zones is common, and fenestral porosity occurs in a few places. All are modified by nonfabric-selective channel and vuggy porosity and in some instances by fractures.« less

Log-Analysis Problems Associated with Bimodal Pore System, Interlake Formation, North Dakota: ABSTRACT

Abstract: The Interlake Formation is a Silurian-age sequence of dolostones, which produces hydrocarbons in the Williston basin. Log analysis of numerous Interlake wells from the Nesson anticline reveals that both water-productive and hydrocarbon-productive zones commonly have calculated water saturations in excess of 60%. These high calculated water saturations, in zones that produce water-free hydrocarbons, appear to be the result of a bimodal pore system. Non-fabric selective vugular pores are the major type of porosity seen in visual examination of Interlake cores. These vugs have been interconnected by fracturing and are responsible for most of the hydrocarbon production. The matrix that separates the vugs is composed of small equant dolomite crystals and also contains large am unts of intercrystalline microporosity, which is interconnected by pore throats less than 0.5 µm across. These small pore throats result in low permeability and high capillary pressures; thus the microporosity is capable of holding 100% irreducible water, whereas the vugular pores produce water-free hydrocarbons. Because it composes up to 50% of the total porosity, this microporosity drastically reduces the resistivity of the formation. Recognition that a formation contains a significant amount of microporosity is important not only in preventing bypassed production, but also in determining reserves and exploration economics. Determination of the percentage of effective porosity cannot be made using electric log or conventional core analysis. A combination of special core analysis and petrographic techniques is needed to better define the amount of effective porosity. End_of_Article - Last_Page 296------------

Mechanical transport and porous media equivalence in anisotropic fracture networks

Abstract: The objective of this work is to investigate the directional characteristics of hydraulic effective porosity in an effort to understand porous medium equivalence for continuous and discontinuous fracture systems. Continuous systems contain infinitely long fractures. Discontinuous systems consist of fractures with finite lengths. The distribution of apertures (heterogeneity) has a major influence on the degree of porous medium equivalence for distributed continuous and discontinuous systems. When the aperture distribution is narrow, the hydraulic effective porosity is slightly less than the total porosity for continuous systems, and greater than the rock effective porosity for discontinuous systems. However, when heterogeneity is significant, the hydraulic effective porosity is directionally dependent and greater than total porosity for both systems. Non-porous medium behavior ws found to differ for distributed continuous systems and for continuous systems with parallel sets. For the latter systems, hydraulic effective porosity abruptly decreases below total porosity in those particular directions where the hydraulic gradient and the orientation of a fracture set are orthogonal. The results for the continuous systems with parallel sets also demonstrate that a system that behaves like a continuum for fluid flux may not behave like a continuum for mechanical transport. 3 references, 13 figures.

Time-Temperature Reconstructions of Diagenetic Systems: ABSTRACT

Abstract: Predicting the distribution of porosity and permeability enhancement in hydrocarbon reservoirs can be achieved by integrating the generation of carboxylic acids, phenols, mineral oxidants, and liquid hydrocarbons in time-temperature space. Such predictive models can be constructed by linking data from oil-field water chemistry, source rock geochemistry, clay mineralogy, clastic diagenesis, thermal modeling and basin analysis. The detailed organic and inorganic geochemistry and the thermal scenarios used in the time-temperature analysis must be basin specific. Predictive time-temperature models using kerogen-specific kinetic parameters have been developed for two tectonic settings: rift or "pull-apart" basins, and intermontane or "Laramide" basins. From these integrated reconstructions, the optimum conditions and capacity for porosity and permeability enhancement can be predicted. The optimum conditions for porosity and/or permeability enhancement are: (1) short migration distances, (2) rapid evolution from organic solvent generation to the liquid hydrocarbon window (thermal environments associated with crustal attenuation or overpressuring could cause such perturbations), (3) adequate fluid flux (organic acids are highly water soluble), and (4) available conduits in potential reservoir rocks (fractures, unconformities, or preserved original porosity). End_of_Article - Last_Page 868------------

Rock Types, Pore Types, and Hydrocarbon Exploration: ABSTRACT

Abstract: A proposed exploration-oriented method of classifying porosity in sedimentary rocks is based on microscopic examination of cores or cuttings. Factors include geometry, size, abundance, and connectivity of the pores. The porosity classification is predictive of key petrophysical characteristics: porosity-permeability relationships, capillary pressures, and (less certainly) relative permeabilities. For instance, intercrystalline macroporosity typically is associated with high permeability for a given porosity, low capillarity, and favorable relative permeabilities. This is found to be true whether this porosity type occurs in a sucrosic dolomite or in a sandstone with pervasive quartz overgrowths. This predictive method was applied in three Rocky Mountain oil plays. Subtle "pore throat" traps could be recognized in the "J" sandstone (Cretaceous) in the Denver basin of Colorado by means of porosity-permeability plotting. Variations in hydrocarbon productivity from a Teapot Formation (Cretaceous) field in the Powder River basin of Wyoming were related to porosity types and microfacies; the relationships were applied to exploration. Rock and porosity typing in the Red River Formation (Ordovician) reconciled apparent inconsistencies between drill-stem test, log, and mud-log data from a Williston basin wildcat. The well was reevaluated and completed successfully, resulting in a new field discovery. In each of these three examples, petrophysics was fundamental for proper evaluation o wildcat wells and exploration plays. End_of_Article - Last_Page 845------------

Eocene and Upper Cretaceous Carbonate Reservoirs in East-Central Tunisia: ABSTRACT

Abstract: Regionally, well-defined belts of lowest Eocene (Ypresian) Metlaoui carbonates trend northwest-southeast. On the northeast is an open-marine, basinal facies of planktonic foraminiferal micrite and marl. Thick bars of shallow marine nummulitic wackestone, packstone, and grainstone trend northeastward at an angle to the paleoshelf. Lagoonal or supratidal carbonates are widespread between the shelf deposits and thick evaporites that crop out in intermontane basins. The reservoir is confined largely to nummulitic packstone, and visible effective porosity is best developed between forams in zones filled with sand-size debris where secondary solution-enlargement has occurred. Porosity within nummulite chambers, while abundant, is ineffective, although a few open fractures were observed in cores. This lithology tested oil in 2 recent wildcats and is a commercial reservoir at Sidi El Itayem and Ashtart fields. Distribution of Zebbag carbonates of Late Cretaceous (Turonian) age is more complex. A northwest-southeast-trending platform is bounded on 3 sides by basinal shale and micrite with planktonic forams which grade into a transitional facies of micrite and wackestone that shows some evidence of shallow-water deposition, such as dolomitization, bioclasts, rare ooliths, etc. Predominately back-reef and lagoonal bioclastic wackestones and packstones occur in narrow belts, apparently controlled at least locally by block faulting. The rest of the platform lithology comprises mostly dolomite and dolomitic limestone. The most significant porosity is interparticle (generally solution-enlarged) in foram packstones, but intraparticle porosity in forams and rudists commonly enhances the reservoir. Intercrystalline porosity in dolomitized zones is common, and fenestral porosity occurs in a few places. All are modified by nonfabric-selective channel and vuggy porosity and in some instances by fractures. End_of_Article - Last_Page 238------------