fax 01-972-952-9435. AbstractOil identification and quantification in low resistivity laminated sand-shale sequences is a major challenge for petrophysics and reservoir engineers; essentially because the thickness of the sand laminas is usually bellow the vertical resolution of the resistivity logging tool. The presence of this lithology generates electrical anisotropy where horizontal resistivity is highly affected by the conductivity of the laminar shale volume, while vertical resistivity is higher and more sensitive to the laminar sand electrical properties. Once identified the productive low resistivity problem the prediction of movable water, creates enormous uncertainty when it comes to decide if this laminated sand should be open to production in the well. All this issues have caused the underestimation of Oil-In-Situ volumes and the lost of thousands of oil production per day in the upper Misoa Formation Reservoirs in western Venezuela. The incorporation of resistive image logs in the geological analysis of upper Misoa Reservoirs, have shown the existence of thinly laminated sand-shale sequences with laminations of an inch thick and less. indicated that 90% of the water contained in the reservoir was irreducible, so it would not be produced.After completing the low resistive sands, production logging tests and well production showed 1300 BBD with 4% of water. This case opened a great opportunity in western Venezuela fields where this type of lithology can be found in most of the wells drilled trough Eocene reservoirs.
fax 01-972-952-9435. AbstractOil identification and quantification in low resistivity laminated sand-shale sequences is a major challenge for petrophysics and reservoir engineers; essentially because the thickness of the sand laminas is usually bellow the vertical resolution of the resistivity logging tool. The presence of this lithology generates electrical anisotropy where horizontal resistivity is highly affected by the conductivity of the laminar shale volume, while vertical resistivity is higher and more sensitive to the laminar sand electrical properties. Once identified the productive low resistivity problem the prediction of movable water, creates enormous uncertainty when it comes to decide if this laminated sand should be open to production in the well. All this issues have caused the underestimation of Oil-In-Situ volumes and the lost of thousands of oil production per day in the upper Misoa Formation Reservoirs in western Venezuela. The incorporation of resistive image logs in the geological analysis of upper Misoa Reservoirs, have shown the existence of thinly laminated sand-shale sequences with laminations of an inch thick and less. indicated that 90% of the water contained in the reservoir was irreducible, so it would not be produced.After completing the low resistive sands, production logging tests and well production showed 1300 BBD with 4% of water. This case opened a great opportunity in western Venezuela fields where this type of lithology can be found in most of the wells drilled trough Eocene reservoirs.
fax 01-972-952-9435. AbstractIn complex geological sequences composed by clastic and carbonatic rocks, where the matrix can be formed by several minerals, such as calcium carbonate, silica and magnesium carbonate, the determination of reservoir properties and rock quality represents a major challenge. Using conventional logs to calculate total and effective porosity in this type of reservoirs can lead to underestimation or overestimation of pore space in the rock and do not provide information about pore size and porosity distribution associated with irreducible water saturation that possibly will impact of reservoir permeability. To address these problems the response of the Nuclear Magnetic Resonance Log was calibrated to the petrophysical and geological properties measured in core. Correlation models were generated for total porosity, permeability and pore throat radius; which could be used in future wells of the area, where core data is not available. A relation between the predominant pore throat radius calculated with the Pittman R45 equation (1992) and the irreducible water saturation from the Nuclear Magnetic Resonance Log was obtained. From this analysis five petrofacies were obtained: megaporous, macroporous, mesoporous, microporous and nanoporous, being predominant the macroporous, mesoporous, and the nanoporous. Total Porosity from the Nuclear Magnetic Resonance correlates very well with the total porosity data from core analysis. To calibrate permeability values derived from NMR data two different T2 cutoffs and Coates-Timur equation constants were used. Showing a relation with sedimentological facies described in macroscopic whole core analysis.
This work is the result of authors' experience in complex reservoirs such as the calcitic-lithic sandstones of the Chicontepec Formation, in the Chipontepec Channel Basin. These rocks, highly reactive to acids, present problems of low permeability; they are often fractured but production decline rapidly in time. The diagenesis experienced by these reservoirs is very complicated because the large amount of carbonate lithics, igneous and metamorphic components present, which can be mixed with detrital clays and dissolution of fossils (moldic porosity). The Chicontepec Formation is a turbidite sequence deposited in shallow waters in a submarine canyon with submarine fans, benthic foraminifera, some charred plant remains, and graded and convolute cross-lamination. It is composed by alternating well cemented calcareous-clayey-sandstones, and dark gray calcareous shale. It exhibits conglomerate horizons, consisting of chert and platform limestone clasts. Petrographically it is composed by very fine grained to middle and, occasionally, course litarenite; consisting of carbonate lithic (mudstone), monocrystalline quartz, plagioclase (sericitized) and a minor lithic igneous, metamorphic, silt and shale components. The main authigenic cements are kaolinite, chlorite, calcite, ankerite and interstratified I/S. The facies described from core samples were adjusted with microfacies obtained from thin sections where permeabilities ranging 0.1 to 400 milidarcy, and porosities between 4 to 15% and occasionally 20% could be differentiated. The described type of porosity is mainly intergranular, with some intragranular and moldic porosity. The analysis of high technology logs, such as magnetic resonance and image logs, permitted us facies modeling by using a 3D multivariate analysis of Coates permeability, effective porosity, shale volume and volume of irreducible water to represent facies described in the analyzed core samples and to obtain an integrated Petrophysical-Geological model. The study of these diagenetic facies allowed us to predict which of the electro-facies were susceptible to high reactivity and select the best candidates for stimulation.
fax 01-972-952-9435. AbstractIn complex geological sequences composed by clastic and carbonatic rocks, where the matrix can be formed by several minerals, such as calcium carbonate, silica and magnesium carbonate, the determination of reservoir properties and rock quality represents a major challenge. Using conventional logs to calculate total and effective porosity in this type of reservoirs can lead to underestimation or overestimation of pore space in the rock and do not provide information about pore size and porosity distribution associated with irreducible water saturation that possibly will impact of reservoir permeability. To address these problems the response of the Nuclear Magnetic Resonance Log was calibrated to the petrophysical and geological properties measured in core. Correlation models were generated for total porosity, permeability and pore throat radius; which could be used in future wells of the area, where core data is not available. A relation between the predominant pore throat radius calculated with the Pittman R45 equation (1992) and the irreducible water saturation from the Nuclear Magnetic Resonance Log was obtained. From this analysis five petrofacies were obtained: megaporous, macroporous, mesoporous, microporous and nanoporous, being predominant the macroporous, mesoporous, and the nanoporous. Total Porosity from the Nuclear Magnetic Resonance correlates very well with the total porosity data from core analysis. To calibrate permeability values derived from NMR data two different T2 cutoffs and Coates-Timur equation constants were used. Showing a relation with sedimentological facies described in macroscopic whole core analysis.
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