Based on 991 groups of analysis data of shale samples from the Lower Member of the Cretaceous Eagle Ford Formation of 1317 production wells and 72 systematic coring wells in the U.S. Gulf Basin, the estimated ultimate...Based on 991 groups of analysis data of shale samples from the Lower Member of the Cretaceous Eagle Ford Formation of 1317 production wells and 72 systematic coring wells in the U.S. Gulf Basin, the estimated ultimate recovery(EUR) of shale oil and gas of the wells are predicted by using two classical EUR estimation models, and the average values predicted excluding the effect of engineering factors are taken as the final EUR. Key geological factors controlling EUR of shale oil and gas are fully investigated. The reservoir capacity, resources, flow capacity and fracability are the four key geological parameters controlling EUR. The storage capacity of shale oil and gas is directly controlled by total porosity and hydrocarbon-bearing porosity, and indirectly controlled by total organic carbon(TOC) and vitrinite reflectance(Ro). The resources of shale oil and gas are controlled by hydrocarbon-bearing porosity and effective shale thickness etc. The flow capacity of shale oil and gas is controlled by effective permeability, crude oil density, gas-oil ratio, condensate oil-gas ratio, formation pressure gradient, and Ro. The fracability of shale is directly controlled by brittleness index, and indirectly controlled by clay content in volume. EUR of shale oil and gas is controlled by six geological parameters: it is positively correlated with effective shale thickness, TOC and fracture porosity, negatively correlated with clay content in volume, and increases firstly and then decreases with the rise of Ro and formation pressure gradient. Under the present upper limit of horizontal well fracturing effective thickness of 65 m and the lower limit of EUR of 3×10^(4) m^(3), when TOC<2.3%, or Ro<0.85%, or clay content in volume larger than 25%, and fractures and micro-fractures aren’t developed, favorable areas of shale oil and gas hardly occur.展开更多
Understanding of fundamental processes and prediction of optimal parameters during the horizontal drilling and hydraulic fracturing process results in economically effective improvement of oil and natural gas extracti...Understanding of fundamental processes and prediction of optimal parameters during the horizontal drilling and hydraulic fracturing process results in economically effective improvement of oil and natural gas extraction. Although modern analytical and computational models can capture fracture growth, there is a lack of experimental data on spontaneous imbibition and wettability in oil and gas reservoirs for the validation of further model development. In this work, we used neutron im- aging to measure the spontaneous imbibition of water into fractures of Eagle Ford shale with known geometries and fracture orientations. An analytical solution for a set of nonlinear second-order diffe- rential equations was applied to the measured imbibition data to determine effective contact angles. The analytical solution fit the measured imbibition data reasonably well and determined effective con- tact angles that were slightly higher than static contact angles due to effects of in-situ changes in veloci- ty, surface roughness, and heterogeneity of mineral surfaces on the fracture surface. Additionally, small fracture widths may have retarded imbibition and affected model fits, which suggests that aver- age fracture widths are not satisfactory for modeling imbibition in natural systems.展开更多
基金Supported by the PetroChina Science and Technology Department Project(2012A-4802-02)National Key Basic Research and Development Program(2014CB239000)。
文摘Based on 991 groups of analysis data of shale samples from the Lower Member of the Cretaceous Eagle Ford Formation of 1317 production wells and 72 systematic coring wells in the U.S. Gulf Basin, the estimated ultimate recovery(EUR) of shale oil and gas of the wells are predicted by using two classical EUR estimation models, and the average values predicted excluding the effect of engineering factors are taken as the final EUR. Key geological factors controlling EUR of shale oil and gas are fully investigated. The reservoir capacity, resources, flow capacity and fracability are the four key geological parameters controlling EUR. The storage capacity of shale oil and gas is directly controlled by total porosity and hydrocarbon-bearing porosity, and indirectly controlled by total organic carbon(TOC) and vitrinite reflectance(Ro). The resources of shale oil and gas are controlled by hydrocarbon-bearing porosity and effective shale thickness etc. The flow capacity of shale oil and gas is controlled by effective permeability, crude oil density, gas-oil ratio, condensate oil-gas ratio, formation pressure gradient, and Ro. The fracability of shale is directly controlled by brittleness index, and indirectly controlled by clay content in volume. EUR of shale oil and gas is controlled by six geological parameters: it is positively correlated with effective shale thickness, TOC and fracture porosity, negatively correlated with clay content in volume, and increases firstly and then decreases with the rise of Ro and formation pressure gradient. Under the present upper limit of horizontal well fracturing effective thickness of 65 m and the lower limit of EUR of 3×10^(4) m^(3), when TOC<2.3%, or Ro<0.85%, or clay content in volume larger than 25%, and fractures and micro-fractures aren’t developed, favorable areas of shale oil and gas hardly occur.
基金supported as part of the Center for Nanoscale Controls on Geologic CO_2 (NCGC)an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Basic Energy Sciences (No. DE-AC0205CH11231)+2 种基金a graduate fellowship through the Bredesen Center for Interdisciplinary Research at the University of Tennesseesupported by the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences, Chemical Sciences, Geosciences, and Biosciences DivisionEdmund Perfect ’s research was sponsored by the Army Research Laboratory (No.W911NF-16-1-0043)
文摘Understanding of fundamental processes and prediction of optimal parameters during the horizontal drilling and hydraulic fracturing process results in economically effective improvement of oil and natural gas extraction. Although modern analytical and computational models can capture fracture growth, there is a lack of experimental data on spontaneous imbibition and wettability in oil and gas reservoirs for the validation of further model development. In this work, we used neutron im- aging to measure the spontaneous imbibition of water into fractures of Eagle Ford shale with known geometries and fracture orientations. An analytical solution for a set of nonlinear second-order diffe- rential equations was applied to the measured imbibition data to determine effective contact angles. The analytical solution fit the measured imbibition data reasonably well and determined effective con- tact angles that were slightly higher than static contact angles due to effects of in-situ changes in veloci- ty, surface roughness, and heterogeneity of mineral surfaces on the fracture surface. Additionally, small fracture widths may have retarded imbibition and affected model fits, which suggests that aver- age fracture widths are not satisfactory for modeling imbibition in natural systems.
