When, for a hydrocarbon deposit, the porosity, density and saturation of the rock, saturating fluid, the permeability, and the electrical formation factor are known, formulas for calculating the equivalent thermal conductivity can be used, by which this property is expressed, depending on the properties of deposit, more easily measurable.These computational expressions are the result of correlations between experimental determinations performed for the physical properties of a very large number of samples in the field.But these equations introduce measurement errors or interpretations by the authors of the research, which often lead to quite large differences from reality.That is why we introduced an experimental model to determine the thermal conductivity and we determined this property on rocks taken from the productive layers of crude oil and gas from some geological research wells conducted in the Moesica Platform, Romania.We also managed to introduce computational relationships between thermal conductivity and density and porosity of extracted rocks.The role of these experiments is to find a new method for determining the thermal conductivity, a property necessary to simulate the flow of oil fluids and the design of oil recovery techniques.

Formation evaluation in thin bed lamination is challenging and classic petrophysical workflow would results in underestimation of true hydrocarbon pore thickness and consequently underestimation of hydrocarbon in place in oil and gas fields. Due to deficiency of conventional well logs to detect thin bed shale sand laminations, they appear as non- hydrocarbon bearing low resistivity interval on well logs. True log response cannot be recorded in thin bed shale sand lamination intervals since thickness of these layers is lower than logging tool resolution. Logging tools can only record the average log response of shale and sand together – rather than true response of sand - anywhere the thickness of each lamination falls below vertical resolution of logging tools. Forward modeling and inversion workflow was applied in a thinly laminated shaly sand reservoir to calculate true hydrocarbon pore thickness. The process of forward modeling and inversion was optimized by using Genetic Algorithm approach by developing a computer code. A new workflow for formation evaluation was proposed for formation evaluation in thin bed shale sand laminations and verified successfully. The result was fully integrated and verified with core, well log and production data. True hydrocarbon pore thickness was increased, and new perforation interval was suggested based on the findings.

The thermal conductivity of rocks is a property necessary to be determined at the beginning of the exploitation of oil and gas deposits, both for the design of secondary extraction (hot water injection, steam) and for the development of tertiary extraction technologies (CO2 injection, injection flue gas, and initiation of underground combustion). In this chapter, we present a new method for determining the thermal conductivity of rocks and we also analyzed the relationships between this parameter and the properties of oil and gas collector rocks (density, porosity).

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In the exploitation of oil and gas reservoirs, thermal conductivity is the property of greatest importance in the application of secondary and tertiary oil fluid recovery techniques. This is why this property has been analyzed by estimating its value using several calculation models. But each model for calculating the value of this property is burdened by the fact that in the reservoir, the rocks are not like the chosen models (being made up of geological conglomerates with various inclusions). This paper presents a technique for estimating thermal conductivity (by energy transfer between overlying strata) and determining its value by a new calculation model. The paper also determined the thermal conductivity values for several rocks constituting some Romanian reservoirs, the aim of this material being to analyze the thermal behavior of rocks in condensed gas-rich areas.