This paper describes a new method based on the analysis of non-steady state wellbore temperature distributions impacted by geothermal temperature profile, Joule-Thomson and adiabatic effects in reservoir flow to describe near wellbore parameters such as permeability distribution and to estimate flow rate distribution between producing layers. The solution of the inverse problem with respect to parameters of near wellbore zone is based on the quantitative analysis of the transient baro-thermal effects resulting from the single-phase fluid flow from the reservoir into the wellbore. In the steady state case the reservoir thermal effect is the same as the throttling (Joule-Thomson) one. It is reduced to the adiabatic effect while the fluid is stagnant. In the general case for non-steady state flow the change of reservoir fluid temperature is a combination of frictional heating and cooling resulting from the expansion of the fluid. Non-isothermal well testing (NIT) relies on the analysis of these fluid temperature changes. The method discussed in this paper allows evaluating parameters of near wellbore region (permeability and radius of damaged zone) and could be complimentary to the conventional well testing practices for a single-layer reservoir and to estimate flow rate distribution among the pay zones in a multi-layer case (zonal allocation). The paper develops mathematical models and presents the results of numerical simulation for transient processes after the start of the production phase and during well test operations including multi-rate testing. Limited to the particular cases of unsteady processes after specific wellbore operations (changes of production regimes and shut-ins), the transient analytical solutions assume that the fluid may be considered incompressible and that no conductive heat transfer occurs. In order to take into account compressibility and thermal conductivity, detailed numerical modeling has been performed. The paper compares the numerical results to experimental data and shows that the fluid heat capacity in wellbore perforated zone must be considered for appropriate interpretation of initial bottomhole temperature change versus time, in particular for small rates. Based on the analysis of the simulation results, an inverse model solution for the estimation of the near wellbore zone parameters from reservoir fluid temperature and wellbore pressure transients is proposed. The method comprises first-order estimation from analytical solution and their further numerical refinements by non-linear regression for the system "reservoir-wellbore". Example of interpretation of non-isothermal well testing field data is presented demonstrating the usefulness of this new methodology.

The history of development and the state of the art of well temperature logging in Russia is described in the paper. As it is known, the first logging in oil wells were temperature ones. In 1906 D. Golubyatnikov made the first measurement of temperature distribution along the well bore using the maximal thermometer. In 1932 it was developed the first electronic well thermometer. From 1970 in practice of field reserarches the high sensitive thermometers with resolution of 0.01K are used: it is registered and analyzed the temperature changes of hundreds and tens parts of degree, caused by Joule-Thomson effect and adiabatic effect. The development of theoretical and methodical basis of well thermometry was made by several groups of Moscow oil institute (now it is RGUNG), VNIINeft (Moscow), Kazan state university (Kazan) and Bashkir state university (Ufa). In Bashkir SU the model of the first industrial small-size well thermometer STL-28, theoretical basis of thermometry of transient processes in the well and formations were developed and the wide practical experience of solution of different problems in oil wells by thermometry was accumulated. At present time the most volume of production log is accounted to thermometry. In the paper it is given the examples of field cases from Bashkiria, Tataria and Western Siberia by means of well thermometry in production (flowing, rod pumping and ESP ones) and injection wells, and also during the development by the gas (air) compressor, swab and jet pump. The results of practical testing of new methods of well thermometry as "active thermometry", which is based on local inductive heating of casing on different depths and observation of the transient temperature behavior, and "infrared thermometry" for survey of "dry intervals" of the well above the liquid level. Also it is discussed the mathematical models, used at interpretation of temperature log. The most recent results are connected with quantitative interpretation of pressure and temperature transients with the purpose of determination of flow rates and individual parameters (for example radius and permeability of damaged zone) of formation in multilayer wells. Introduction The first measurements along the well are made by D. Golubyatnikov of Azerbaijan. He carries out measurements by points using a thermometer with great lag. However an increasing of volumes of temperature researches is observed after the development of electronic thermometer by V.N. Dakhnov in 1932. During this period it is investigated mainly the gas wells. As the result of the combining of temperature measurement data it was published the monography 1 by Daknov V.N. and Dyakonov D.I. in 1952. From the end of 60s and beginning of 70s the highly sensitive thermometers with resolution of 0.01K are used in the filed reserarches: the temperature changes of hundreds and tens parts of degree, caused by Joule-Thomson effect and adiabatic effect are registered and analyzed. The development of theoretical and methodical basis of well thermometry was made by several groups of Moscow oil institute (now it is RGUNG), VNIINeft (Moscow), Kazan state university (Kazan) and Bashkir state university (Ufa). In Bashkir SU the model of the first industrial small-size well thermometer STL-28, theoretical basis of thermometry of transient processes in the well and formations were developed and the wide practical experience of solution of different problems in oil wells by thermometry was accumulated.

In the paper it is described the achievements in the modern well thermometry and analyzed the problem of quantitative interpretation. It is known the first logging in oil wells was temperature one. In 1906 the professor D. Golubyatnikov on Apsheron (Azerbaijan) at first time measured the temperature distribution along the wellbore using the maximal thermometer. Today the high sensitive electronic thermometers with resolution of 0.01K are used: it is registered and analyzed the temperature changes of hundreds and tens parts of degree, caused by Joule -Thomson effect and adiabatic effect. At present time the most volume of production log is accounted to thermometry. In the paper it is given the examples of field cases from Russia by means of well thermometry during the development using the gas (air) compressor. The results of practical testing of new methods of well thermometry as "active thermometry", which is based on local inductive heating of casing on the different depths and observing the behavior of the transient temperature, are discussed. It's known that despite many attempts to develop quantitative interpretation methods, the interpretation of temperature measurements has remained mostly qualitative. The paper describes the mathematical models, used at interpretation of temperature logs. The most recent results are connected with quantitative interpretation of quasi-steady temperature distribution along the well and pressure and temperature transients with the purpose of determination of flow rates and individual parameters (for example, radius and permeability of damaged zone) of formation in multilayer wells. The application of the developed models to interpretation of temperature measurements in the different wells demonstrated on real field data sets.

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