**8. Basin Modeling**

The natural geological bodies of the formation level—where the processes of oil and gas formation that took place (and/or are taking place) are oil and gas source formations or horizons (OGSH)—are responsible for the oil and gas potential of various regions. The total oil and gas-producing potential of a particular oil and gas basin (OGB) should be estimated by the amount of OM contained in OGSH. The OGSH are characterized by certain concentrations of OM, types of OM, and a certain volume, i.e., thickness and area of development, as well as the maturity of OM (catagenesis). In order for OGSH (or their combination) to become a focus of oil and gas formation (OGF), the minimum values of HC migration densities from them should be at least 50 thousand tons/km<sup>2</sup> (50 million nm3/km2) under ideal accumulation conditions (the immediate vicinity of the reservoir and its optimal thickness). In general, the border focal density of migration can be assumed to be 100 thousand tons/km<sup>2</sup> (100 million m3/km2). In order to identify the localization of OGF, it is necessary to determine the area of development and the thickness of the OGSH

as well as the concentration of OM (Corg) in them; it is also necessary to identify the degree of catagenesis of OM, and with the use of the created models of the generation-migration of HC, to calculate the scale of migration for the type of OM corresponding to this OGSH.

On the territory of the TP SB, the Domanik-Tournaisian formation and the Silurian formations (29% and 25% for oil, respectively) play the main role in terms of the scale of oil and gas formation; Lower Permian formations (12% for oil and 22% for gas) can be attributed to less significant ones.

The Domanik-Tournaisian formation was continued from the continent to the sea on the basis of facies constructions and seismic data, according to the results of which reef bodies were identified, outlining the zone of the pre-reef facies of the sublatitudinal strike. Thin layers of domanikoid rocks are found in the section of the clay-carbonate deposits of well No. 1—Pakhancheskaya, which is typical for some areas of the reef facies near the reef body [50]. These interlayers are enriched with OM and are not of interest from the standpoint of large-scale oil and gas formation, but they indicate the relative proximity of the development of domanikoids of the formation scale. The thickness of the Domanik OGSH increases in general from west to east—from 20 to 300 m—as the age range of the formation expands. The average concentrations of Corg vary in the range of 0.6–1.5%. In the work area, the Domanik-Tournaisian OGSH is characterized by the following degrees of catagenesis of OM: MK21 and MK22 [49].

The mudstones of the Lower Ordovician and Upper Cambrian are characterized by shallow-sea facies formation conditions and sapropel organic matter. At the same time, a large proportion of algal OM is noted in Ordovician samples. The degree of transformation of rocks according to bituminology remains relatively low, but the correctness of these definitions is questionable, especially given the large spread of analysis results.

The modern geothermal regime of the TP SB is characterized by the relatively low intensity of the thermal field; the average geothermal gradients in the section do not usually exceed 2.5 ◦C/100 m [25]. In the TPB, the so-called abbreviated ("subdonets") zonality of the catagenesis of OM [49] was established due to the intense geothermal regime in the past (paleogradients of the order of 5 ◦C/100 m), which is characteristic of Paleozoic basins. Table 1 shows the paleodepth dimension of such a scale compared with measurements of the reflectivity of vitrinite Ra (measurements carried out in oil) and Ro (measurements carried out in air) (Table 1) [49,50].


**Table 1.** The dimension of the Paleozoic catagenetic scale of the Timan–Pechora basin and its comparison with the optical indicators of vitrinite [35,36].

The scheme of the distribution of the centers of oil and gas generation of hydrocarbons in the water area of the Timan–Pechora basin is shown in Figure 10.

**Figure 10.** The main centers of generation of the north of the TPP and the directions of migration.

The thicknesses of the OGSH of the Silurian complex in the work area vary in the range of 50–400 m, while the direction of thickness changes and their gradients are aligned with the seismic map of the total thicknesses of O2-D1. Average concentrations of Corg in the OGSH (S1-2) vary in the range of 0.25–0.60% (isocarbs 0.3; 0.5). The organic matter in the Silurian OGSH is characterized by the degree of catagenesis of MK3 (Figure 11).

**Figure 11.** Scheme of catagenesis of OM on the roof of Silurian deposits.

In most of the territory of the TBP, the catagenetic scale has a shortened, so-called subdonets character corresponding to the maximum paleogradient of 5 ◦C/100 m. The scale is justified by numerous data on the definitions of the reflectivity of vitrinite.

The data of analytical geochemical studies made it possible to create a basin model for the studied region. The modeling of the processes of generation, migration, and accumulation of hydrocarbons was carried out using the TemisFlow software package. The geological history of the basin is modeled with backstripping technology, which involves restoring the history of the basin's dives by sequentially removing structural horizons. The modeling of the geochemical history is carried out based on the kinetic model of hydrocarbon transformation based on the work of the French Institute of Petroleum (IFP). The applied modeling method makes it possible to link disparate geochemical and structural materials to assess the qualitative characteristics of oil and gas source rocks and the degree of realization of their potential, as well as to obtain approximate but reasonable quantitative data on the scale of generation and migration of hydrocarbons.

As a result of the work carried out to assess the oil and gas source potential in the Lower-Middle Paleozoic section of the MKM, the main prospects for the formation of possible hydrocarbon accumulations are associated with Silurian oil-producing strata. It was not possible to separate the Lower and Upper Silurian deposits at the research site, and the characteristics of their oil and gas production potential are given together.

To the west of the fault separating the structures of the Pechora–Kolva Aulacogen from the Malozemelsko–Kolguevskaya monocline, a band of the absence of oil and gas source strata is mapped. The scale of the thicknesses of the OGSH of the Silurian complex in the work area is 50–400 m, while the direction of change in thicknesses and their gradients are aligned with the seismic map of the total thicknesses of O2-D1. Average concentrations of Corg in the OGSH (S1-2) vary in the range of 0.25–0.60%.

To create the model, the constructed structural maps for the main reflecting horizons and thickness maps between them were used, the degree of erosion as a result of large interruptions in sedimentation was estimated, and prospective source strata, forecast reservoirs, and fluid barriers of the lower structural floor of the MKM were estimated (Figure 12).

At the initial stage of the work, the 1D modeling method was also used to evaluate the catagenetic transformation of the OM according to deep-drilling data. The modeling of the temperature history of catagenetic changes in rocks was based on T.K. Bazhenova's opinion that in Paleozoic basins, there was a reduced catagenetic zonality due to an increased paleogradient of temperatures of up to 4.5–5.0 ◦C/100 m, as well as data on the modern thermal gradient for mobile foundation blocks (which was the MKM) at 2.4–2.7 ◦C/100 m [6,46].

To assess the reliability of fluid traps and the generation potential of oil source rocks, the results of the logging data analysis for deep wells extrapolated to the territory of the entire site were used. The surfaces of fluid traps and oil source rocks were calculated by the method of convergence in the gap between the main structural horizons, by a proportional division of the thickness between the main deep surfaces. The correction of the depth reference was made based on the borehole data, where it is possible. To assess erosion, it was assumed that the maximum apparent thickness of the eroded complex was almost equal to the thickness of the complex before erosion. Furthermore, the amount of erosion was calculated as the difference between the maximum thickness and the current thickness. At the same time, the paleoterrain at the time of the formation of the analyzed complex was noted, and the thickness of the filling of paleotroughs was excluded from the calculation, for which the correlation of additional horizons was performed [40,48,50].

**Figure 12.** Structural map of the foundation (RH VI) with tectonic zoning [41].

Tectonic elements: Suborder: G—Timan ridge, D—Izhma–Pechora syneclise, E— Malozemelsko–Kolguevsky megablock (monocline), Zh—Pechora–Kolva megablock (aulacogen), I—North Pechora Sea monocline; 1st order: D1—Neritsky stage, D4—Novoborsko– Sozvinskaya structural zone, D5—Seduyakhinsko–Malolebedinsky disjunctive megalithic bank, E1—Korginskaya stage, E2—West–Kolguevskaya depression, E3—Kolguevsky block, E4—Malozemelsky block, Zh1—Pechora–Kozhvinsky graben, Zh2—Denisovsky block; 2nd order: D51—Seduyakhinsky disjunctive shaft, D52—Seduyakhinsko–Yantygsky bridge, E30—West Kolguev uplift, E31—Kolguev structural zone of horsts and grabens, E32— Peschanomorskoye structural zone, E41—Naryan–Marsky stage, E42—Udachnaya stage, E43—Kharitseysko–Shapkinskaya stage; 3rd order: E30-1—Bugrinsky dome, E30-2—West– Bugrinsky stage, E41-1—South Sengei dome, E41-2—East Seduyakhinsky ledge, E41-3—Nerut graben, E42-1—Sengei graben, E42-2—Sengei horst, E43-1—Khareysky stage, E43-2—South Anorgayakhsky dome.

The basin model was carried out on the basis of the data on the geochemical characteristics (including lithology, type of organic matter, and the history of immersion).

It was revealed that the organic matter in the Silurian OGSH in the work area is characterized by a degree of catagenesis from MK2 to MK3, while only in the extreme northern periphery is it up to MK4-5. The main center of generation is shown in Figure 13.

The identification and substantiation of oil source strata in the modeling process was a difficult task due to the small size of the work area and its marginal position in the oil and gas basin. Belonging to the reservoir, fluid trap or oil source strata was determined based on the lithological characteristics of the strata and the content of Corg. Bundles in the Upper Silurian and Upper Devonian Domanik deposits have been tested as oil and gas source strata [3,47,49].

The Upper Silurian deposits in the work area are a layer of clay-carbonate interlayer, which was studied in natural outcrops along the Dolgaya River. An analysis of the GC curve of well No. 1—Naryan–Marsky allowed us to take the thickness of the interlayers with the

oil source potential as 1/3 of the total thickness of the Upper Silurian deposits. The Lower Devonian sediments developed locally; they do not have widespread distribution. Their development is associated with the most loaded sections of the pre-Timan structural stage.

**Figure 13.** (**a**) Scheme of catagenetic zonality of Upper Silurian deposits [47]; (**b**) Scheme of the development of the center of generation and the migration direction of the HC of the Malozemelsko– Kolguevskaya monocline and the zones of its junction with adjacent territories [42].
