High-pressure Reservoir Research Articles

FACTORS AFFECTING THE GAS RECOVERY COEFFICIENT AT GAS CONDENSATE FIELDS WITH ABNORMALLY HIGH RESERVOIR PRESSURE

The results of numerical experiments to assess the influence of abnormally high reservoir pressure on the dynamics of pressure reduction at the bottom and the supply circuit, flow rate and life of wells are presented. It is shown that the growth of the anomaly coefficient of reservoir pressure has a positive effect on the dynamics of the considered indicators. It has been established that in hydrocarbon deposits with abnormally high reservoir pressures, the rock pressure of up to 75% is balanced by the pressure of saturating hydrocarbons. High rates of gas extraction, achieved due to large depressions on the reservoir in producing wells, lead to reservoir deformation, which in fractured and fractured-pore reservoirs leads to the closure of hydrocarbon filtration channels. Using the example of the Severny Nishan gas condensate field, it is shown that the deformation of the reservoir is the main reason for the low efficiency of development and the abandonment of half of the gas reserves in the reservoir. Hydraulic fracturing technology is recommended for the extraction of residual gas reserves. With an increase in the depth of the productive horizons, the proportion of hydrocarbon deposits with abnormally high reservoir pressures is steadily increasing. As it is known, the energy potential of productive layers is largely determined by the activity of the legal aquifer area. There are elision and infiltration natural water pressure systems. The experience of developing hydrocarbon deposits with AVPD shows that this factor, depending on the geological and physical conditions of the deposits, can affect the oil and gas recovery coefficient as a positive (increasing) and negative (decreasing) factor. At the same time, as positive factors, there is a higher concentration of reserves in the specific volume of the deposit, relatively high well flow rates, ensuring the gushing of wells for a long time, maintaining high reservoir properties of reservoir rocks, and as a negative factor, a decrease in stability and susceptibility of oil and gas saturated reservoirs to deformation processes.

Foam Based Fracturing Fluid Characterization for an Optimized Application in HPHT Reservoir Conditions

Water-based fracturing fluids are among the most common fluid types used in hydraulic fracturing operations. However, these fluids tend to cause damage in water-sensitive formations. Foam comprises a small amount of base fluid, and compressible gas such as carbon dioxide and nitrogen has emerged as a more ecologically friendly option to fracture such formations. Foam is an attractive option since it has a low density and high viscosity. The applicability of foamed frac fluid is characterized by foam stability and rheology, encompassing the viscosity and proppant carrying ability. The foam quality, pressure and temperature affect the foam rheology. Generally, foam viscosity and stability increase with pressure but decrease when the temperature increases. Hence, it is essential to preserve foam stability in high pressure and high temperature (HPHT) reservoir conditions. The addition of nanoparticles could increase the thermal stability of the foam. This article provides the basis of foam-based fracturing fluid characterization for an optimal application in HPHT reservoir conditions. Then, focusing on improving thermal stability, it reviews the research progress on the use of nanoparticles as foam stabilizing agent. This paper also sheds light on the literature gaps that should be addressed by future research.

Physical simulation of the nonlinear transient flow behavior in closed high-pressure gas reservoirs. Part II: pressure-depleted flow experiments on fractured cores

Physical simulation of the nonlinear transient flow behavior in closed high-pressure gas reservoirs. Part II: pressure-depleted flow experiments on fractured cores

Effectiveness of cellulose polyanionic-based polymers on the measurement of rheological properties of water-based drilling fluids in high-pressure high-temperature fractured shale reservoirs

High-pressure, high-temperature fractured shale reservoirs are types of unconventional reservoirs that need proper drilling operations for adequate efficiency. Proper measurement of drilling fluid’s rheological properties is of importance for drilling operations that may increase the penetration rate on the one hand with proper design. Therefore, the success of drilling operations strongly depends on the proper design of drilling fluids. In this paper, we experimentally investigated the effect of potassium and sodium formate fluid on the rheological properties of drilling fluid for fractured shale core samples. The yield point and apparent viscosity for muds consisted of cellulose polyanionic and cellulose polyanionic-ultralow polymers higher than base muds. It indicates the effect of formate salts in increasing thermal stability. In addition, in polymer-based muds, more amounts of formate salts have been used, indicating the low fluid loss volume. Consequently, the shale recovery rate for potassium formate fluids is higher than sodium formate fluid.

Diagenetic facies classification and characterization of a high-temperature and high-pressure tight gas sandstone reservoir: A case study in the Ledong area, Yinggehai Basin

A high-temperature and high-pressure tight gas sandstone reservoir, located in the Ledong area of the Yinggehai Basin, shows considerable resource potential. However, the diagenetic characteristics of this reservoir remain unclear. In this study, reservoir petrology and diagenetic characteristics were systematically investigated through different experimental methods. Further, the porosity and diagenetic evolution models were constructed. The methods employed included petrophysical analysis, observation of core and thin sections, and grain-size distribution analysis. Furthermore, scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy, cathodoluminescence, carbon and oxygen isotope analysis, digital image analysis, mercury injection capillary pressure tests, and micro-CT imaging were also employed. In the study area, gravity-flow channel sediments composed of feldspathic litharenite primarily developed in a restricted submarine canyon. And tight sandstones in target formation have an average porosity of 9.34% and permeability of 1.79 mD. Mechanical compaction and cementation (mainly illite and ferrocalcite) were regarded as crucial roles in the densification process. Further, the diagenetic evolution model indicated that the reservoir underwent a high degree of thermal diagenetic evolution. Five diagenetic facies types were classified and characterized at multiple scales. Moreover, a vertical distribution model of different diagenetic facies was also developed considering the overpressure, depth of formation, thickness and frequency of mudstones, and injection concentration of the CO2. This study helps to improve the understanding of the diagenetic characteristics and diagenetic facies types in high-temperature and high-pressure clastic reservoirs.

Influence Factors of the Bottom Hole Flow Pressure in a High-Pressure and High-Temperature Condensate Gas Reservoir: Applicability Analysis

Influence Factors of the Bottom Hole Flow Pressure in a High-Pressure and High-Temperature Condensate Gas Reservoir: Applicability Analysis

One practical CaCl2-weighted fracturing fluid for high-temperature and high-pressure reservoir

The petroleum industry is increasingly focused on high-temperature, high-pressure oil reservoirs, and they face challenge in generating sufficient surface construction pressure without exceeding the capabilities of surface equipment. To address this issue, the industry now predominantly relies on weighted fracturing fluid. However, weighted fracturing fluid is unreasonably expensive and difficult to break up. Thus, researchers are urged to develop a low-cost, weighted fracturing fluid that can be easily fractured. Thus, polymer thickener GTA, with poly-hydroxy groups capable of complexing calcium ions, and boron–zirconium composite crosslinker JL903, which is capable of delaying crosslinking, were developed. A CaCl2-weighted fracturing fluid system was developed using the polymer and crosslinker. The density of the system can reach 1.28 g/cm3, crosslinking time can be delayed by 5 min, and the temperature resistance can reach 140 °C. Following the use of ammonium persulfate as a gel breaker, sodium bromate was used as a discriminative gel breaker to resolve the issue of excessive residue content in the weighted fracturing fluid.

Numerical Trend Analysis for Factors Affecting EOR Performance and CO2 Storage in Tight Oil Reservoirs

Improved oil recovery from tight oil reservoirs to fulfill the fossil fuel requirements and the CO2 storage to meet the net carbon zero objectives are the two motivations of this work. CO2 is a major anthropogenic greenhouse gas and its emission to our plants’ atmosphere is hazardous, particularly causing global warming. Therefore, its injection in the sub-surface oil-bearing formations not only improves the oil recovery but also reduces the carbon footprint from the planet. In this study, a mechanistic numerical simulation model is built using typical U.S. tight oil reservoir rock and fluid properties. The reservoir model is equipped with a hydraulically fractured single horizontal well that is subjected to multiple sensitivities using the huff-n-puff technique. Detailed CO2 trapping and diffusivity mechanisms at the nanopore scale are discussed that numerically define the CO2 solubility in formation oil and it’s trapping phenomenon into the nanopore spaces. The results show that CO2 injection works predominantly to achieve significant incremental oil recovery. Also, the reservoir with lighter in-situ fluid composition and higher reservoir pressure further enhances the oil recovery due to improved diffusivity and the solubility of CO2 into the reservoir fluid. It is also found that the increased number of huff-n-puff cycles and the incremental CO2 injection volume in each cycle not only enhance the oil recovery performance but likewise help to trap a larger volume of CO2 into a reservoir. A few diagnostic contour plots are also presented in this study to demonstrate the simultaneous effect of multiple hydraulic fracture parameters and the CO2 injection volume for the directional EOR and CO2 trapping performance. The findings of this study can help for a better understanding of designing EOR operations in tight oil reservoirs to achieve both goals concurrently.

Pneumatic system for pressure probe measurements in transient flows of non-ideal vapors subject to line condensation

This paper presents the design, construction and commissioning of a pneumatic system for pressure probe measurements in flows of organic vapors in non-ideal conditions, namely in the thermodynamic region close to the liquid–vapor saturation curve and the critical point where the ideal gas law is not applicable.Experiments were carried out with fluid siloxane MM (hexamethyldisiloxane, C6H18OSi2), commonly employed in medium/high temperature Organic Rankine Cycles (ORCs), in the Test Rig for Organic VApors (TROVA), a blow-down wind tunnel at the Laboratory of Compressible fluid dynamics for Renewable Energy Applications (CREA lab) of Politecnico di Milano. TROVA operation is intrinsically transient due to its batch nature, with a low frequency content (∼1Hz) related to the emptying of the high-pressure reservoir feeding the test section.The challenges linked to possible condensation in pneumatic lines, such as vapor–liquid menisci, hydrostatic head and mass-sink effects, were evaluated by means of theoretical calculation and experiments. To avoid these issues, a nitrogen-flushed pneumatic system for absolute and differential pressure measurements was designed and successfully tested with superheated MM vapor expanding in planar choked converging nozzles characterized by a portion with constant cross-sectional area yielding design Mach numbers of 0.2, 0.5 and 0.7. Commissioning of the complete system including a probe was performed with the first ever testing of an L-shaped Pitot tube in non-ideal subsonic flows of siloxane MM vapor at Mach numbers M=0.2 and 0.5. Measurement delay issues were identified and assessed through a dynamic testing procedure, and were solved by reducing the overall pneumatic lines volume including the one hidden within pressure transducers. The correct performance of the complete system was therefore verified for probe measurements of total, static and dynamic pressure in non-ideal flows of organic vapors. This sets the foundation for future directional pressure probes calibration and use in the characterization of such flows, as in direct measurement of total pressure losses across shocks and in testing of ORC turbine blade cascades.

Determination of miscible CO2 flooding analogue projects with machine learning

Using analogue reservoirs for comparison and benchmarking is a comprehensive method for ensuring accurate measurement and gaining a better understanding of potential oil recovery enhancement prospects. The approach of leveraging information from analogue reservoirs is extended to CO 2 EOR project management in this study. We present a novel application of machine learning clustering algorithms to the rapid identification of analogues for new projects without having to sift through massive amounts of data. We use machine learning clustering methods to group successfully executed miscible CO 2 flooding projects into clusters of projects with similar fluid/reservoir characteristics and to identify analogues for new target projects. Porosity, permeability, oil gravity and viscosity, reservoir pressure and temperature, minimum miscibility pressure (MMP), and depth were all input parameters. Data from nearly 200 miscible CO 2 EOR projects around the world were clustered using the Agglomerative Hierarchical Clustering Algorithm (HCA), K-Means, and K-Median techniques. To reduce information redundancy in high-dimensional data, Principal Component Analysis was used as a pre-processing step. Three evaluation indices (the Davies Bouldin, Calinski Harabasz, and Silhouette Coefficient Scores) were used to compare the efficiency of the clustering algorithms and choose the best one for this dataset. A Principal Component – weighted Euclidean distance similarity metric was computed using three existing miscible CO 2 flooding projects (Weyburn, Hansford Marmaton, and Paradis) as test cases to confirm the clustering results. The clustering analysis identified five different classes of miscible CO 2 projects, each with its reservoir and fluid characteristics. Type 1 projects, in general, are those that are carried out primarily in shallow carbonate reservoirs at the lowest temperatures and pressures of any database project with typical porosity and permeability. More than 60% of Type 2 projects are in sandstone reservoirs. They are at shallower depths with lower temperatures, pressures, porosities, and permeabilities than project Type 4. Type 3 projects are typically undertaken in carbonate reservoirs with medium depths and temperatures but the highest reservoir pressures. This project type has medium porosity and permeability. In comparison to project Type 2, Type 4 primarily consists of projects conducted in sandstone formations at great depths with high reservoir temperatures and pressures. The porosity and permeability of these project types are average. Finally, Type 5 projects are typically undertaken in sandstone formations at average depths, temperatures, and pressures, but with the greatest porosity and permeability of all project types. In addition to the clustering analysis, the distance similarity metric used in this work identified projects that were most like the test miscible CO 2 flooding project cases. Key rock and fluid properties, well types, and best infill drilling strategies, recovery improvement strategies, and production performance can all be learned from identified analogue projects. This data can be used to improve the operational, technical, field, and well-planning decisions for new CO 2 flooding projects. The workflow demonstrated in this paper is easily adaptable to data sets from other flooding projects. • K-Means clustering model can be used effectively to categorize miscible CO 2 flooding projects. • The global miscible CO 2 flooding projects in collated dataset can be broadly divided into five classes by K-means clustering model. • A calculated Principal Component – weighted Euclidean distance similarity metric can be used to successfully validate cluster groupings. • Ideal analogue projects with similar fluid and reservoir properties can be identified with K-Means and the distance-based metric

Unconventional natural gas accumulation system

Unlike conventional natural gas accumulations, unconventional ones have obvious particularity in reservoir forming conditions, enrichment mechanism, distribution modes, prediction method, and exploration technology. Analyzing the reservoir forming process and main controlling factors of unconventional natural gas accumulations under the guide of the hydrocarbon accumulation system theory is of great significance for unconventional natural gas reservoir evaluation and prediction. Based on the reservoir forming mechanism and distribution mode, the unconventional natural gas accumulation systems are divided into six types, including shale gas, coalbed methane, tight carbonate gas, tight sandstone gas, water-soluble gas, and gas hydrate. According to the concept of “element–function–structure” in the hydrocarbon accumulation system theory and the relationship of “gas source rock–migration system–accumulations distribution”, the unconventional gas accumulation system is divided into six “source–location” types. The characteristics of the other five types of unconventional gas accumulation systems except gas hydrate are analyzed. The following results were obtained. (1) Shale gas, coalbed methane and tight carbonate gas belong to an intra-source type unconventional gas accumulation system, characterized by intense gas supply capacity, lack of either a transport system or secondary migration, integration of source, reservoir and caprock, in-situ accumulation, and so on. (2) Tight sandstone gas and water-soluble gas belong to a marginal unconventional gas accumulation system of source rock, characterized by diverse gas origin, near-source accumulation in adjacent layers of source rocks, internal migration within reservoirs, and so on. (3) Basin tectonic evolution, sedimentary environment and late tectonic events control the types of unconventional gas accumulation systems: The Paleozoic marine sediments in South China are conducive to the formation of shale gas and tight carbonate gas accumulation systems; The marine–continental transitional facies deposits of Upper Paleozoic distributed in the South and North China are conducive to the development of coalbed methane, shale gas and tight sandstone gas accumulation systems; In the Middle and East China, Mesozoic–Cenozoic deep-water continental deposits are more conducive to the deep tight sandstone gas and shale gas accumulation systems, while shallow water continental basins are more conducive to the formation of coalbed methane, tight sandstone gas and shale gas accumulation systems. Water-soluble gas is widely found in the Cenozoic shallow-buried areas rich in organic matter or high-pressure reservoirs adjacent to gas source rocks.

Rock shale mineral composition influence on oil and gas generation process (results from laboratory experiments)

The paper presents the results of the hydrothermal processes of organic matter transformation in the rocks of the Bazhenov Formation and the Domanik horizon laboratory modeling. Shortterm exposure of samples to high temperatures (350 C) and reservoir pressures (300 atm) in the presence of water made it possible to simulate the processes that could take place in the reservoir, and to transform kerogen up to 70% in the rocks initially containing immature kerogen or kerogen in the beginning of the oil window. It was found that the amount of liquid hydrocarbon compounds generated during cracking mainly linearly depends on the content of organic matter in the rocks, while the gas generation is described by a rate function. The mineral composition of rocks does not affect the size of the formed pores, but in some cases it controls the amount of formed hydrocarbon compounds and the composition of the liquid products. It is shown that the increase in the amount of carbonate material in the rocks inhibits oil and gas generation process, there are lower amounts of light components in the products, and some of hopanes are absent. At the same time, high concentrations of siliceous material in the rocks with low amount of other components and, probably, the presence of pyrite can stimulate the generation process, in some cases allowing an increase in the amount of produced “synthetic” oil and gas, to achieve a greater variety of reaction products. The results obtained in general make it possible to examine the processes of individual hydrocarbon compounds formation during hydrothermal processes, to identify catalysts and inhibitors of the generation mechanism, and also, from a practical point of view, to propose conditions for reservoirs stimulation and development of technologies for increasing oil production and generation of oil with a controlled composition in situ.

Isothermal Desorption Hysteretic Model for Deep Coalbed Methane Development

The adsorption/desorption mechanism of coalbed methane is significant for gas control and coalbed methane exploitation; scholars have done a lot of research on it and generally have confidence in that temperature, pressure, and moisture are central factors affecting the adsorption of coalbed methane. Considering the reduction of recovery efficiency caused by desorption hysteresis in deep coalbed methane drainage, the effects of high reservoir pressure, high gas content, and low permeability on the hysteresis index were analyzed. A desorption hysteresis model based on the combination of dual-porosity media and traditional Langmuir adsorption theory was proposed. By comparing with the four experimental data of Ma et al., the advantages of the new model in fitting desorption data were investigated. Based on the new desorption hysteresis model, the hysteresis index was calculated from the adsorption capacity and desorption capacity under the abandonment pressure. The hysteresis index under different coal sizes and adsorption pressure were calculated, and a good linear relationship was found between the adsorption pressure and the hysteresis index. Through a large number of field production data analysis, the following conclusions are drawn: as the adsorption pressure increases, the hysteresis index enhances; when the coal sample size increases, the hysteresis index also increases. Finally, by comparing experimental data from deep and shallow coal samples, the influence of desorption hysteresis on deep coalbed methane mining was explored. This paper draws the conclusion that although the gas content in deep coalbed methane is considerable, its hysteresis index is also enhanced, which makes coalbed methane development more difficult. The findings of this study can provide theoretical support for coal bed gas control and coal bed methane heat injection mining.

Thermal flue gas utilization in delivering unconventional geo-energy

Conventionally, thermal technology of steam-assisted gravity drainage (SAGD) has been an effective method to unlock unconventional petroleum resources with extra-high viscosity. However, in the middle and late stages of SAGD, there are some problems such as low oil production rate and high water cut, and a large amount of greenhouse gases can be generated, which may disrupt the balance of the geo-energy supply and greenhouse-gas mitigation. Therefore, in this study, with a novel thermal SAGD technology with flue gas in the late stage of SAGD, the steam chamber and fluid-steam ratio could be substantially improved, which thereafter results in better production performance. Meanwhile, it can effectively use the flue gas produced by SAGD to reduce carbon emissions. A laboratory-scale three-dimensional (3-D) physical was manufactured to simulate the practical processes, including interwell warm-up, conventional and novel flue gas-assisted SAGD at high-pressure and high-temperature reservoir conditions. The experiments demonstrated the injected flue gas concentrated on the top of the physical model due to the gravity override, which contributes to control the heat loss to the atmosphere and subsurface systems. In this way, the thermal sweep efficiency was substantially increased since the heat retained was employed for the lateral-direction steam chamber development. Meanwhile, the addition of flue gas induced the reduction of steam partial pressure, which finally resulted in chamber temperature decreasing by approximately 10 °C. On the other hand, the instantaneous fluid-steam ratio was found to increase from 0.06 to 0.24 at the highest, while the water cut decreased by around 20%. All the aforementioned changes in physical parameters contribute to 7.75% higher petroleum fluid recovery. Overall, the newly-developed technology has been validated to significantly extend production lifetime and improved recovery efficiency. This study will support the foundation of more general application pertaining to greenhouse gases mitigation and sustainable productions in unconventional geo-energy.

An Optimization-Based Method for the Explicit Production Data Analysis of Gas Wells

This work aims at the exploration of production data analysis (PDA) methods without iterations. It can overcome limitations of the advanced type curve analysis relying on the iterative calculation of material-balance pseudotime and current explicit methods reckoning on specific production schedule assumptions. The dynamic material balance equation (DMBE) is strictly proved by the integral variable substitution based on the gas flow equation under the boundary dominated flow (BDF) condition and the static material balance equation (SMBE) of a gas reservoir. We introduce the pseudopressure level functionγ(p) and the recovery factor functionR(p) to rewrite the DMBE in terms of observed variableYand estimated variableYe; then the PDA can be transformed into an optimization problem of minimizing the error betweenYandYe. An optimization-based method for the explicit production data analysis of gas wells (OBM-EPDA), therefore, is developed in the paper, capable of determining the BDF constant and gas reserves explicitly and accurately for variable rate and/or variable flowing pressure systems. Three stimulated cases demonstrate the applicability and validity of OBM-EPDA with small errors less than 1% for estimated values of both reserves andY. Not second to previous studies, the field case analysis further proves its practicability. It is shown that the nonlinear relation ofγtoRcan be represented by a polynomial function merely dependent on the inherent properties of the gas production system even before sorting out the production data. The errors of observed variableYprovided by OBM-EPDA facilitate the data quality control, and the elimination of outliers not subject to the BDF condition improves the reliability of the analysis. For various gas systems producing whether at a constant rate, a constant bottomhole pressure (BHP), or under variable rate and variable BHP conditions, the proposed method gives insights into the well-controlled volume and production capacity of the gas well whether in a low-pressure or high-pressure gas reservoir, where the compressibilities of rock and bound water are considered.

Study on Eor Effect and Influencing Factors of Hydrocarbon Gas Flooding after Water Flooding in High-Temperature and High-Pressure Reservoirs

Study on Eor Effect and Influencing Factors of Hydrocarbon Gas Flooding after Water Flooding in High-Temperature and High-Pressure Reservoirs

Study on Eor Effect and Influencing Factors of Hydrocarbon Gas Flooding after Water Flooding in High-Temperature and High-Pressure Reservoirs

Study on Eor Effect and Influencing Factors of Hydrocarbon Gas Flooding after Water Flooding in High-Temperature and High-Pressure Reservoirs

A numerical method for potential implementation of underbalanced drilling in high pore pressure reservoirs

A numerical method for potential implementation of underbalanced drilling in high pore pressure reservoirs

Quantitatively study on imbibition of fracturing fluid in tight sandstone reservoir under high temperature and high pressure based on NMR technology

Reservoir fracturing is one of the main technical means to realize high-efficiency development of low-permeability tight reservoirs in oil fields. With the implementation of reservoir fracturing measures, the imbibition effect is produced after the interaction between fracturing fluid and rocks in oil reservoirs. It is of great guiding significance to study the imbibition mechanism of fracturing fluid and quantitatively evaluate the imbibition effect of fracturing fluid with different pore throats under different conditions for practical development. In this paper, to reveal the mechanism of fracturing fluid imbibition from a microscopic point of view, based on the simulation of high temperature and high-pressure reservoir environment, using nuclear magnetic resonance (NMR) technology and dynamic physical simulation experiments, we quantitatively evaluated the imbibition effect of fracturing fluid with different pore throats at different times and investigated the influence of permeability, wettability, and viscosity of fracturing fluid on imbibition effect of fracturing fluid. The results show that the scale of imbibition of fracturing fluid is between 0.10 ms–51.20 ms. Additionally, the imbibition rate is the fastest in the initial stage of imbibition. Furthermore, the imbibition takes place in micropores (0.10 ms–1.00 ms) first, and then enters mesopores (1.00 ms–10.00 ms), followed by macropores (>10.00 ms) as the reaction time goes on. Also, micropores (0.10 ms–1.00 ms) are the best contributors to the imbibition effect of fracturing fluid, and the imbibition effect tends to be stable at first, followed by mesopores (1.00 ms–10 ms), with the highest contribution, but its imbibition effect is relatively lagging. Last, the imbibition efficiency is positively correlated with permeability, negatively correlated with fracturing fluid viscosity. It is also related to wettability. The imbibition effect of hydrophilic type is better than that of oleophilic type. The more hydrophilic the rock is, the better the imbibition effect is, and the imbibition stability time of the hydrophilic type lags behind that of the oleophilic type.

Литологическая и инженерно-геологическая характеристика пород толбачанской свиты в пределах шахтного поля трубки Мир

The Tolbachan suite presents the complex mining and geological conditions for development the Mir primary diamond deposit at depths of 1000 to 1400 meters. The resumption of mining operations at the field requires a comprehensive study of host rocks, especially in the formation intervals of high-pressure reservoirs of mixed fluid saturation. The study of lithological features and determination of the main physical and mechanical parameters of the formation were carried out in 2020–2021 using standard methods based on core samples of experimental wells. As a result of the studies, the main lithological types of rocks of the Tolbachan Formation were described, and the stratification of the strata according to physical and mechanical properties was performed. The conducted studies allow characterizing the mining and geological conditions for the construction of underground mine workings, as well as to predict the main negative factors affecting the mining operations at the deposit.