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The present work summarizes the results of analysis of unique experimental data on vertical heat flow variations in different geological structures obtained from 15 scientific supper-deep and deep boreholes drilled to the depths of 1600–12262 m within Russian and ICDP programs. The new workflow was applied for the heat flow estimation which is based on (1) precise and detailed thermal conductivity measurements on more than 30000 cores with the new emerging technologies, (2) usage of more than 100 equilibrium and non-equilibrium temperature logs, and (3) determination of conductive heat flow component within 20–100 m intervals along every borehole studied. The data on conductive heat flow variations provides an estimate of vertical variations in the convective heat flow component. The latter reflects the information on variations in reservoir and formation properties and heat- and mass transfer processes in reservoirs and formations. It was established that a conductive component of the heat flow varies between 70 and 100% for the boreholes studied with essential (up to 100%) increase in heat flow within upper depth intervals of 2–4 km in some cases. Terrestrial heat flow values established from the measurements in deep and super-deep boreholes exceed the previous experimental heat flow estimates by 30…130% depending on a region of drilling. During the previous estimates the heat flow values were obtained from the measurements in shallow boreholes and heat flow was determined from averaging temperature gradient and thermal conductivity along boreholes. The established heat flow variations play an important role in the improvement of reliability of basin and petroleum system modeling and prediction of temperatures below the borehole depths. The use of calibrated heat flow distributions is shown to increase the confidence of such studies. Introduction Experimental data on heat flow density and rock thermal properties (thermal conductivity and volumetric heat capacity) are critically important for basin and petroleum system modeling. The results of the modeling depend essentially on heat flow density values and thermal property values for the sedimentary basin under studying integrated in the model. The rock thermal properties determine formation thermal regime in its natural state as borehole as at thermal methods of EOR. It is considered normally that satisfactory data on heat flow and thermal properties could be found in publications and it is a usual practice in oil/gas science and industry at basin and petroleum modeling at present.

New methods and instruments developed for measurement of rock thermal properties (thermal conductivity, thermal diffusivity, volumetric heat capacity, and coefficient of linear thermal expansion) have provided a sharp increase in the quality of experimental data for reservoirs and surrounding formations. Optical scanning technology primarily provides numerous high-precision, nondestructive, noncontact measurements of thermal conductivity and diffusivity directly on full cores, core plugs, and nonconsolidated rock samples and enables determination of thermal property tensor components and the recording of thermal property variations along cores. The instrument for simultaneous determination of thermal conductivity, diffusivity at formation temperature (up to 250 degC), and three-component pressure (pore, confining axial, and lateral) enables measurements at formation conditions to study thermal property variations during the heating of reservoirs and oil production in thermal enhanced oil recovery (EOR). The instrument for measurements of the coefficient of linear thermal expansion at temperatures up to 250 degC within every temperature interval of 20 degC provides measurements on core plugs that account for rock anisotropy. Application of the new techniques to study more than 8,000 cores from 17 Russian oil-gas and heavy oil fields provided a representative thermal property database for sedimentary rocks saturated by brine, oil, and gas, accounting for rock anisotropy and inhomogeneity as well as formation pressure and temperature. New correlations between thermal and other physical properties were established. The new experimental data demonstrated that previous information on thermal reservoir properties often needs to be significantly corrected. The new instruments provided detailed information on the spatial and temporal variations in the thermal reservoir properties during thermal EOR. Authors used this to construct detailed 4D reservoir models for estimation of reservoir thermal regime, thermal losses, and heat and mass transfer within reservoirs, enabling better design and optimization of thermal methods of EOR.

The current results of development of a new production logging (PL) tool based on an azimuthally distributed array of thermal anemometers and aimed at determination of inflow profiles beyond the limits of common mechanical sensors in horizontal wells producing oil and water at low rates are described in this paper. Theoretical background, implementation technique, and experimental prototype (EXP) were developed for the PL tool using azimuthally distributed thermo-anemometer (TA) sensors to obtain a dataset characterizing the production regime in low-rate (below 150 m3/d) oil and water horizontal wells. The new PL tool's TA sensors record overheating profiles along a well that depend on the local velocity of the fluid and its phase composition. The periodic heating regime of the TA sensors enabled measuring the undisturbed fluid temperature for determination of overheating and acquiring high-resolution temperature profiles, thus providing a valuable additional dataset of diagnostic attributes for characterization of the inflow. Laboratory testing allowed determination of calibration dependencies of TA signals versus velocities of single-phase water and oil flows. The calibrations were used for interpretation of data obtained with the PL tool and evaluation of the distribution of fluid phases for cross sections along a well and profiles of phase velocities. These results indicated the new tool's potential for implementation with a standard PL toolstring in low-rate oil and water horizontal wells. Interpretation of the EXP data together with that from standard PL tools enhanced the reliability of the determination of inflow zone intervals, phase composition of an inflowing fluid, and phase distribution of producing fluid along a well. Analysis of the field data established that effective resolution of temperature measurements by the new PL tool is approximately 0.015 K to enable registration of the effective fluid velocity in range of 0.5 to 15 m/min with corresponding resolution of 0.01 to 0.3 m/min to result in a spatial resolution of 1 to 20 m of the recorded parameters for uniform inflow along a horizontal wellbore. The evaluated values of spatial resolution are based on optimized logging speed, taking into account TA measurement specifics, well construction design, and total production rate. In this first field test of the innovative EXP in two horizontal wells producing water and oil at low rates, the tool was conveyed on coiled tubing and tractor. Joint interpretation of data recorded with the EXP and standard PL tools confirmed that the inflow profiles for each well along with profiles of phase velocities and water inflow zones were reliably established.

More than 8,500 measurements of the rock thermal properties – thermal conductivity, thermal diffusivity and volumetric heat capacity – performed on samples of different rock types from 6 terrigenous and carbonaceous heavy oil reservoirs provided the vast experimental data base for 4D reservoir modeling of thermal EOR recovery methods. The experimental results describe the essential spatial variations (more than 100%) in the thermal properties, including thermal rock anisotropy and heterogeneity, within the reservoirs, and significant temporal variations (up to 100% in most cases) in rock thermal properties that are caused by significant changes in reservoir temperature (up to 250 0C) and fluid type (steam, oil and brine) in rock pore space during the heating of reservoirs and oil production. Wide ranges in all thermal properties were determined from the measurements and important information on the correlations between thermal and other petrophysical properties (porosity, elastic wave velocities, etc.) was found. The analyses demonstrate that such spatial-temporal (4D) variations in the thermal properties could not be obtained from the literature data and the existing data base. It was established also that the theoretical modeling of rock thermal properties in modern simulators leads to significant uncertainties in reservoir thermal properties estimation and could result in essential errors in oil production parameters evaluation. The importance of using accurate and representative experimental data on rock thermal properties in simulations of thermal EOR was illustrated by a simplified model of a SAGD process. In the cases simulated, serious influence (up to 50%) from uncertainties in each reservoir thermal properties (the thermal conductivity and volumetric heat capacity) on key outcome parameters – cumulative oil production and steam-to-oil ratio – was observed. Results demonstrated that different thermal properties influence on key production parameters in different ways. It was shown also that reliable data on the thermal properties of both pay zone and surrounding rocks are important for correct estimation of SAGD performance. In particular, the maximum influence of uncertainty in thermal properties of pay zone is established during first years while the influence of uncertainty in thermal properties of surrounding rocks increases with time monotonously. The parametric study showed that production predictions based on empirically derived thermal rock properties may significantly improve simulations and provide field operators with more realistic estimation of the project's economics. The results demonstrate the necessity of detailed experimental investigations of the thermal properties of reservoirs and surrounding rock for the heavy oil field under development to provide necessary reliability of hydrodynamic modeling results.