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Abstract
Increasing interest in the exploration for High Pressure High Temperature (HPHT) petroleum reservoirs and for geothermal reservoirs calls for theoretical and experimental knowledge of temperature effects on sedimentary rocks. Sandstone is one class of sedimentary rocks of interest to both industries, and the physical understanding of temperature effects on mechanical properties as well as governing characteristics of fluid and heat transfer in sandstones can be essential for industrial success.
With respect to temperature influence on elasticity and strength, sandstone samples from three wells in the central North Sea Basin were studied. The samples were collected from depths exceeding 5 km and insitu temperatures above 170°C. This is relevant for drilling operations, because the success and safety of a drilling operation rely on accurate estimates of the subsurface effective stress field. Failure to take into account the significant temperature effects on both stiffness and strength properties may lead to inaccurate stress estimates and thus cause risk. With the intention of experimentally quantifying temperature effects on rock stiffness and strength properties, the three sandstones were tested in the dry state at temperatures from ambient to insitu (170°C). Results show a material stiffening during increasing temperature, reflected in both static and dynamic elastic moduli. These observations can be attributed to thermal expansion of the constituting mineral particles by two mechanisms of different magnitude depending on the boundary conditions. Likewise, strength parameters derived from measurements of shear failure at ambient and insitu temperature show strengthening with temperature. This observation may also be attributed to thermal expansion of constituting minerals. The effective stress field modelled from the conventional Biot equation implies isothermal conditions, but for nonisothermal conditions it is possible to include thermoelastic theory. Results of interpreting logging data by using the conventional as well as the nonisothermal Biot equation to estimate the subsurface effective stress in a North Sea well show that the nonisothermal Biot equation predicts a smaller effective stress. Results further indicate the possibility of a neutral effective stress at great depth so that the overburden load may be carried solely by the pore pressure and thus might be floating on the highly overpressured older layers.
Permeability is a key hydraulic property in both petroleum and geothermal engineering and of great interest with respect to sandstones. Commonly, conventional laboratories derive the apparent liquid permeability of core plugs from empirical or semiempirical corrections to the gas permeability derived from flowthrough experiments. Correcting gas permeability derived from flowthrough experiments to the apparent liquid permeability is conventionally denoted Klinkenberg correction. From flowthrough experiments, liquid permeability on a series of outcrop sandstones shows good agreement with the apparent liquid permeability from classical Klinkenberg correction of gas permeability obtained at laminar flow conditions and thus compatible with linear Darcy’s law. In gas permeability experiments not only Klinkenberg correction is necessary, but also the confirmation of laminar flow so that the linear Darcy equation is valid. For this purpose an estimate of Reynolds number can be done based on apparent pore size as estimated from backscatter electron micrographs. For doing Klinkenberg correction, the number of gas permeability data points can be limited by availability of core material, so estimates of permeability may be based on one or more petrophysical properties, which may not be of hydraulic character. Estimation of permeability from nonhydraulic properties calls for an understanding of the governing petrophysical principles. Results of Nuclear Magnetic Resonance Spectrometry on the sandstone samples used for liquid flowthrough experiments show that the largest pores in the sandstones do not form a continuous path and consequently the smaller pores control the overall permeability.
Because of minimal subsurface coring, assessment of depth variations in thermal conductivity is typically limited to applying empirical relations to downhole logging data, but by combining input parameters from the concepts of rock stiffness and permeability, it is possible to establish a new model for thermal conductivity. Provided a given mineralogical composition, the model can estimate formation thermal conductivity as a function of depth using solely parameters quantified through conventional log interpretation. The applicability is demonstrated by comparing measured data with model predictions of thermal conductivity with input from laboratory data of sandstones identical to ones used in permeability studies, as well as logging data from an exploration well of the Gassum Formation near Stenlille, Denmark.
With respect to temperature influence on elasticity and strength, sandstone samples from three wells in the central North Sea Basin were studied. The samples were collected from depths exceeding 5 km and insitu temperatures above 170°C. This is relevant for drilling operations, because the success and safety of a drilling operation rely on accurate estimates of the subsurface effective stress field. Failure to take into account the significant temperature effects on both stiffness and strength properties may lead to inaccurate stress estimates and thus cause risk. With the intention of experimentally quantifying temperature effects on rock stiffness and strength properties, the three sandstones were tested in the dry state at temperatures from ambient to insitu (170°C). Results show a material stiffening during increasing temperature, reflected in both static and dynamic elastic moduli. These observations can be attributed to thermal expansion of the constituting mineral particles by two mechanisms of different magnitude depending on the boundary conditions. Likewise, strength parameters derived from measurements of shear failure at ambient and insitu temperature show strengthening with temperature. This observation may also be attributed to thermal expansion of constituting minerals. The effective stress field modelled from the conventional Biot equation implies isothermal conditions, but for nonisothermal conditions it is possible to include thermoelastic theory. Results of interpreting logging data by using the conventional as well as the nonisothermal Biot equation to estimate the subsurface effective stress in a North Sea well show that the nonisothermal Biot equation predicts a smaller effective stress. Results further indicate the possibility of a neutral effective stress at great depth so that the overburden load may be carried solely by the pore pressure and thus might be floating on the highly overpressured older layers.
Permeability is a key hydraulic property in both petroleum and geothermal engineering and of great interest with respect to sandstones. Commonly, conventional laboratories derive the apparent liquid permeability of core plugs from empirical or semiempirical corrections to the gas permeability derived from flowthrough experiments. Correcting gas permeability derived from flowthrough experiments to the apparent liquid permeability is conventionally denoted Klinkenberg correction. From flowthrough experiments, liquid permeability on a series of outcrop sandstones shows good agreement with the apparent liquid permeability from classical Klinkenberg correction of gas permeability obtained at laminar flow conditions and thus compatible with linear Darcy’s law. In gas permeability experiments not only Klinkenberg correction is necessary, but also the confirmation of laminar flow so that the linear Darcy equation is valid. For this purpose an estimate of Reynolds number can be done based on apparent pore size as estimated from backscatter electron micrographs. For doing Klinkenberg correction, the number of gas permeability data points can be limited by availability of core material, so estimates of permeability may be based on one or more petrophysical properties, which may not be of hydraulic character. Estimation of permeability from nonhydraulic properties calls for an understanding of the governing petrophysical principles. Results of Nuclear Magnetic Resonance Spectrometry on the sandstone samples used for liquid flowthrough experiments show that the largest pores in the sandstones do not form a continuous path and consequently the smaller pores control the overall permeability.
Because of minimal subsurface coring, assessment of depth variations in thermal conductivity is typically limited to applying empirical relations to downhole logging data, but by combining input parameters from the concepts of rock stiffness and permeability, it is possible to establish a new model for thermal conductivity. Provided a given mineralogical composition, the model can estimate formation thermal conductivity as a function of depth using solely parameters quantified through conventional log interpretation. The applicability is demonstrated by comparing measured data with model predictions of thermal conductivity with input from laboratory data of sandstones identical to ones used in permeability studies, as well as logging data from an exploration well of the Gassum Formation near Stenlille, Denmark.
Original language  English 

Publisher  Technical University of Denmark, Department of Civil Engineering 

Number of pages  72 
ISBN (Print)  9788778775009 
Publication status  Published  2018 
Series  B Y G D T U. Rapport 

Number  403 
ISSN  16012917 
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Dive into the research topics of 'Thermal conductivity, permeability and temperature effects on stiffness and strength properties of sandstones'. Together they form a unique fingerprint.Projects
 1 Finished

Temperature and poroelasticity of sedimentary rocks
Orlander, T., Fabricius, I. L., Andreassen, K. A., Levenberg, E., Revil, A. & Holt, R. M.
01/09/2014 → 06/09/2018
Project: PhD