NMR Study of Reservoirs Containing Fluids with Anomalous Physical and Chemical Properties

Abstract

The main goal of laboratory nuclear magnetic resonance (NMR) measurements is to verify the accuracy of the interpretation of nuclear magnetic logging (NML) data and to adjust this data to a petro physical model. To set up NML data for a petro physical model, it is necessary to perform laboratory NMR measurements, where the accuracy in studied samples depends on simulated saturation with one or other fluids. In most cases, laboratory research comes down to fraction porosity definition on hydrocarbon-cleaned, desalted, dried and saturated with reservoir water samples. Such formations as Bazhenov suite deposits and bituminous sands cannot be studied by NMR using the standard method. Carrying out the extraction leads to change of mechanical properties of samples: cavities appear in samples, they slough, storage capacity changes. Thus, storage capacity and mechanical properties will not correspond to their original properties. It is required to study these formations in naturally occurring saturated state. If the hydrogen index of the saturating fluid is different from unity, then for reliable estimate of storage capacity, a correction for hydrogen index of studied fluid is applied. It is possible to determine hydrogen index of studied fluid in the volume with current methods (oil in the volume, oil-field water in the volume, or their mixture in a certain ratio also in the volume). It is not always possible to determine the hydrogen index of the fluids that saturate the studied rock in the laboratory directly for a number of reasons. Kerogen, bitumen, heavy and light hydrocarbons and water are contained in the pore volume of the Bazhenov suite. (Manuilova, 2017) Bituminous sandstone formations contain extremely-high viscosity index oil with non-uniform viscosity and irreducible water. (Musin, 2015) In both of these cases, the average hydrogen index of the formation fluids is less than unity, therefore, the porosity determined by NMR will be underestimated. It is not possible to obtain fluid influx in the same ration like in a reservoir in these cases, so there is no chance to measure average HI of these fluids. Therefore, very important development stage of NMR technology is to determine the average HI of all fluids in the pore volume. Authors proposed fluid hydrogen index (HI) determination method on naturally saturated core within this work. The proposed method of hydrogen index determination is based on the registration of changes in the volume of the pore fluid by two methods before and after extraction. On one hand, the change in pore fluid volume before and after cleaning is determined by nuclear magnetic resonance. Due to the hydrogen index that is different from the unity, the apparent change in the pore volume fluid will be recorded. Apparent change of pore fluid volume in studied fluid will be recorded because of differing unity. On the other hand, the change in the same volume is determined by the gas volumetric method as the difference in volumes of the solid phase before and after extraction. The volume of the solid phase will be changed by the amount of fluid volume after cleaning the pore space from fluids. Thus, the volume difference of the solid phase before and after extraction will be the true volume of the fluids contained in the researched sample. The hydrogen index will be defined as the ratio of apparent volume to true. The obtained hydrogen index is used as a correction factor to determine the porosity obtained by NMR (laboratory measurements of core with natural saturation and NML). The authors for the first time describe a method for hydrogen index determining directly on naturally saturated core samples which allows us to define the average hydrogen index of all fluids in a rock. The hydrogen index thus allows to introduce correction and determine the porosity more correctly. The shape of the sample does not matter for this method; no additional measurements of reservoir properties are required.