## 4 Discussion
Rocks from Oil field 3 have OM at the peak of oil generation, and, therefore, they demonstrate distinct behavior (samples #16 and #18--Figure 14a,c,d). At the same time, samples #12 and #14 were exposed to the same temperature (463 \({}^{\circ}\)C and 461 \({}^{\circ}\)C, accordingly) and had a relatively same order of porosity and permeability before the experiment. However, their final values of porosity and permeability are drastically different (Table 4, Figure 14). Samples #13 and #14 from oil field 2 show very high gas porosity (26% and 32%) and permeability (5.7 mD and 4.2 mD). It can be explained by specifics of mineral composition (as for argillaceous-siliceous mudstone), higher OM maturity (than that for oil field 1), a higher amount of transformed kerogen (proved by S2 values), or other technical reasons such as the occurrence of large fractures and voids. In other words, it is crucial to account for the rock heterogeneity in original reservoir properties and technical specifics of the experiment when modeling the HPAI for target oil fields. The standard practice of laboratory HPAI experimental data interpretation includes recording the change in temperature profiles during the test. The reservoir and geochemical properties of rock before and after the thermal exposure can be applied to the combustion tube characterization (Figure A4). In other words, data by gas porosimetry, NMR, and Rock-Eval pyrolysis can become an excellent addition to conventional probe sampling (fluid probing and crushed core investigation) due to exclusive information on shale fluid saturation and OM conversion. Hence, it is recommended to enhance the standard laboratory HPAI combustion tube protocol and to include a comprehensive analysis of core plugs using available non-invasive techniques. Known parameters of the tube (section length) and size for each particular sample makes it possible to correlate the saturation level and other parameters with the location of the test cylinder. Thus, complementary analysis of standard rock samples enables the maximum knowledge to be obtained on the physical and chemical processes within the laboratory thermal EOR tests. As with the majority of studies, the design of the current study is subject to technical and experimental limitations that could be addressed in future research. First, limited core material and core fragility caused difficulties when planning the integrated analysis of rock using available methods. For instance, different probe preparation requirements preclude the conduct of multiple tests on a single core. Second, for the same reason, we attempted to analyze the changes in rock properties using a reduced number of recognized experimental techniques. Third, the initial heterogeneity in petrophysical parameters complicated the analysis of factors influencing the change of reservoir properties and saturation for target rock samples. In summary, we demonstrated that a detailed and integrated study of rock samples in laboratory modeling of the thermal EOR method (HPAI or ISC) significantly advances the research results. The further steps of our research involve increasing the number of rock samples investigated and experimental techniques used by adding more novel techniques such as X-Ray microcomputed tomography and low-temperature nitrogen adsorption for investigation of the nano- and micro-sized porous structure of the rock. Figure 14: Cross plot of (**a**) porosity by gas; (**b**) permeability; (**c**) residual saturation by NMR; (**d**) residual TOC vs. temperature. Change of porosity and NMR fluid volume is calculated as follows: Change (fraction) = (parameter before CT – parameter after CT/parameter before CT). Triangle-shaped symbols indicate the measured parameter before CT. Samples #13 and #14 are not demonstrated at (**a**) due to high values of gas porosity (see Table 4).