Tight Oil in Oil-And-Gas Source Carbonate Deposits' Gas Saturation Zones of Gas-Condensate and Oil-Gas Condensate Fields (Russian)

2016 ◽  
Author(s):  
N. Skibitskaya ◽  
M. Bolshakov ◽  
I. Burkhanova ◽  
V. Kuzmin ◽  
D. Surnachev
Keyword(s):  
Oil And Gas ◽  
Gas Condensate ◽  
Tight Oil ◽  
Gas Saturation ◽  
Gas Source ◽  
Oil Gas ◽  
Carbonate Deposits

scholarly journals Interconnection of FSES HE on 21.03.01 “Oil and Gas Business” and Professional Standard “Specialist in Production of Oil, Gas and Gas Condensate” on the Example of Implementation Disciplines

2020 ◽  
Vol 6 (9) ◽  
pp. 401-407
Author(s):  
I. Kvach ◽  
S. Kvach
Keyword(s):  
Higher Education ◽  
Oil And Gas ◽  
Professional Competence ◽  
Oil And Gas Industry ◽  
Gas Condensate ◽  
Professional Activity ◽  
Russian Society ◽  
Technological Equipment ◽  
Professional Standard ◽  
Oil Gas

The article makes an attempt to analyze the situation in the labor market in modern Russian society in connection with new conditions, rapidly changing technologies, digitalization of all production and management processes, and what awaits a university graduate in a new labor reality. The article deals with the issue of conjugation of federal educational standards of higher education of generation 3++ and professional standards in the implementation of bachelor’s programs. The study is based on the example of interfacing FSES HE 21.03.01 “Oil and Gas Business” and the professional standard “Specialist in oil, gas and gas condensate production” in the context of the implementation of disciplines Technological equipment of the oil and gas industry and Maintenance and repair of oilfield equipment and the formation of professional competence: able to carry out work for diagnostics, maintenance, repair and operation of technological equipment in accordance with the chosen field of professional activity at the Yugra State University. The positive aspects of the interface between PS and FSES of HE in the implementation of educational programs of higher education, the difficulties arising on the way of this process and possible solutions are noted.

scholarly journals Carbonate oil and gas source rocks wettability alteration due to influence of polymer-colloidal drilling mud

2021 ◽  
pp. 17-27
Author(s):  
N. A. Skibitskaya ◽  
◽  
I. O. Burkhanova ◽  
M. N. Bolshakov ◽  
V. A. Kuzmin ◽  
...  
Keyword(s):  
Surface Properties ◽  
Oil And Gas ◽  
Pore Space ◽  
Space Structure ◽  
Source Rocks ◽  
Wettability Alteration ◽  
Drilling Mud ◽  
Rock Samples ◽  
Gas Saturation ◽  
Gas Source

Evaluation of rock wettability is an important task, since this parameter determines the distribution of water and oil in the reservoirs and their relative and phase permeability. The reliability of evaluation the wettability of rock samples depends on the drilling-in conditions during core sampling and core sample preparation methods. The investigation of the surface properties of the core from the Orenburg oil and gas condensate field showed that using of polymer-colloidal drilling mud leads to hydrophilization of the samples' surface. To obtain information on the actual wettability values of rock samples taken from wells drilled with polymer-colloidal drilling mud a method for estimating the relative (predominant) wettability of rocks based on petrophysical and lithological studies data is proposed. The authors suggest that the extraction of oil and gas source rock samples leads to irreversible changes in surface properties that cannot be restored. Keywords: selective wettability; relative wettability; predominant wettability; polymer-colloidal drilling mud; residual gas saturation; trapped gas saturation; pore space structure; extraction.

Three-Phase Imbibition Relative Permeability

10.2118/90-pa ◽  
1961 ◽  
Vol 1 (04) ◽  
pp. 254-258 ◽  
Author(s):  
J. Naar ◽  
R.J. Wygal
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Water Flooding ◽  
Pressure Curve ◽  
Complete Wetting ◽  
Oil Saturation ◽  
Gas Saturation ◽  
Three Phase ◽  
Oil Gas ◽  
Wetting Fluid

Abstract An equation for three-phase (water, oil, gas) imbibition oil permeability is developed, assuming the water to be the dominant wetting fluid. Oil isoperms are obtained for consolidated sandstones characterized by. The evolution of an oil-gas system imbibing water from is shown to proceed along a line of constant oil saturation with increasing oil permeability and decreasing gas saturations. When the gas saturation cannot be reduced further, the system evolves along a line of constant with decreasing oil saturation and permeability. The initial gas saturation is shown to reduce markedly the effect of complete wetting by either oil or water on flow performance. Introduction Imbibition oil isoperms are required for performance prediction when a well is producing water, oil and gas. This situation occurs in multiphase displacements such as underground combustion, steam injection and the water flooding of highly depleted reservoirs. In a recent paper, a model was presented for the prediction of two-phase imbibition characteristics. This paper extends the imbibition model to the case of three phases by assuming that the water is the dominant wetting fluid. The following results were obtained from the model:an analytical expression of oil isoperms;oil isoperms as functions of reduced water, oil and gas saturations, valid for all sandstones having a capillary pressure curve which can be approximated by; andevaluation of the three-phase flow performance as dictated by complete wetting by either oil or water. The agreement between predicted and observed oil recovery in the presence of a gas phase, reported in Ref. 1, is a partial support for the present development. However, experimental data are not available at this time to check fully the model predictions. Perhaps this paper will stimulate the collection of such data. THEORETICAL The imbibition model of a porous medium has been described previously, and the reader is referred to the paper of Naar and Henderson for details. In brief, the model is formed by the random interconnection of straight capillaries, with a provision for the blocking of the non-wetting phase by the invading wetting fluid.

scholarly journals Features of the brine water composition of the Vendian - Lower Cambrian Middle Botuoba oil-gas-condensate field during the catagenesis time

2020 ◽  
Vol 15 (3) ◽  
Author(s):  
N.F. Chistyakova ◽  
◽  
V.V. Dravante ◽  
A.I. Sivtsev ◽  
◽  
...  
Keyword(s):  
Chemical Composition ◽  
Lower Cambrian ◽  
Oil And Gas ◽  
Salt Water ◽  
Water System ◽  
Gas Condensate ◽  
Artesian Basin ◽  
Water Composition ◽  
Genetic Types ◽  
Oil Gas

The salt water omposition of underground brines of the Vendian - Lower Cambrian sections of the Middle Botuoba oil-gas-condensate field during the catagenesis stage is considered; the peculiarity of which is the presence of polygenic waters in certain block traps of B5 and Б1 levels: sodium sulfate, sodium hydrogencarbonate and chlorine-magnesium genetic types together with the prevailing chlorine-calcium genetic type. The zoning of the groundwater of the strata by mineralization and four genetic types of groundwater has been carried out. The directions of water entry into the reservoirs formed at the stage of catagenesis and entering together with hydrocarbons in the corresponding traps are established. It is shown that, while maintaining the mechanism of formation of the salt water composition in the "rock-water" system, the polygenicity of the formation waters present simultaneously in one reservoir layer reflects a regular change in the components of their chemical composition during the transition from the artesian basin to the oil and gas basin. The most sensitive ions of the chemical composition of groundwater, reflecting the transition of the artesian basin to the new geological state of the catagenesis stage, are sulfate, bicarbonate, and sodium ions.

A Two-Phase Flow Model for Reserves Estimation in Tight-Oil and Gas-Condensate Reservoirs Using Scaling Principles

2021 ◽  
pp. 1-18
Author(s):  
L. M. Ruiz Maraggi ◽  
L. W. Lake ◽  
M. P. Walsh
Keyword(s):  
Gas Flow ◽  
Single Phase ◽  
Oil And Gas ◽  
Two Phase Flow ◽  
Gas Condensate ◽  
Tight Oil ◽  
Phase Flow ◽  
Reservoir Pressure ◽  
Single Phase Flow ◽  
Two Phase

Summary A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multiphase flow, which exist once the reservoir pressure falls below the bubble/dewpoint. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. In addition, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight-oil wells in the Wolfcamp Formation of west Texas. First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudopressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells. The results of this research are the following: First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors (URFs) for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the pressure/volume/temperature (PVT) properties, which shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two-phase and single-phase solutions under boundary-dominated flow (BDF) conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells because they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubblepoint. Finally, the application of the two-phase model provides a better fit when compared with the single-phasesolution. The present model requires very little computation time to forecast production because it only uses two fitting parameters. It provides more realistic estimates of URFs and EURs, when compared with single-phase flow solutions, because it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight-oil and gas condensate wells.

Application of multi-stage hydraulic fracturing in the development of Achimov sediments at the Urengoy oil and gas condensate field

2020 ◽  
pp. 38-48
Author(s):  
E. V. Panikarovskii ◽  
V. V. Panikarovskii ◽  
M. M. Mansurova ◽  
M. V. Listak
Keyword(s):  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Gas Condensate ◽  
Hydraulic Fractures ◽  
High Permeability ◽  
Main Method ◽  
Reservoir Rocks ◽  
New Methods ◽  
Multi Stage ◽  
Oil Gas

The development of deep-lying Achimov deposits makes it possible to extract additional volumes of gas and gas condensate in the fields with decreasing production, as well as implement strategies to introduce new methods to increase oil, gas and condensate production. The decrease in well productivity during the development of gas condensate fields requires the use of new methods of intensification of production. The main method for increasing the productivity of Achimov wells is hydraulic fracturing. The choice of hydraulic fracturing technology for low-permeability Achimov deposits is especially important for creating large hydraulic fractures and high permeability, as well as maintaining the filtration characteristics of reservoir rocks. Multi-stage hydraulic fracturing is the most effective method of intensifying gas and gas condensate production in the development of the Achimov deposits.

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