scholarly journals PHYSICOCHEMICAL PROCESSES THAT CAUSE OIL RECOVERY COEFFICIENT INCREASE WHEN IMPURITIES OF NANOSIZED METAL PARTICLES ARE ADDING INTO AQUEOUS SOLUTIONS

2021 ◽  
pp. 98
Author(s):  
Viktor I. Lesin
Keyword(s):  
Aqueous Solutions ◽  
Oil Recovery ◽  
Metal Particles ◽  
Recovery Coefficient ◽  
Physicochemical Processes ◽  
Coefficient Increase

scholarly journals EVALUATING THE DEGREE OF COMPLEXITY OF TIGHT OIL RECOVERY BASED ON THE CLASSIFICATION OF OILS

2020 ◽  
pp. 76-81
Author(s):  
G. Efendiyev ◽  
M. Karazhanova ◽  
D. Akhmetov ◽  
I. Piriverdiyev
Keyword(s):  
Cluster Analysis ◽  
Oil Recovery ◽  
Fuzzy Cluster ◽  
Fuzzy Cluster Analysis ◽  
Recovery Coefficient ◽  
Reservoir Permeability ◽  
Oil Density ◽  
The Relationship ◽  
Degree Of Recovery

The article discusses the results of the use of cluster analysis in assessing the degree of oil recovery complexity and its impact on the performance indicator. For this purpose, clustering was performed using a fuzzy cluster analysis algorithm. It should be noted that along with the deposits of heavy and highly viscous oils, a large share of hard-to-recover reserves is also confined to conditions with very low reservoir permeability values. Data on viscosity, oil density and oil permeability of in-situ conditions from various fields of Kazakhstan are collected. Using the results of this classification, a statistical analysis of indicators of various types of hard-torecover oils was performed. In the process of analysis, a generalized characteristic was determined for each class of oil, including viscosity, oil density and reservoir permeability. The generic characteristic is a linear transformation of the three characteristics. The results were subjected to statistical processing. At the same time, an attempt was made to establish and analyze the relationship between the degree of recovery complexity of hard-to-recover oils and oil recovery coefficient. In the course of the analysis, the average values of the oil recovery coefficient and the index of the degree of recovery complexity of hard-to-recover oil within each cluster were calculated and the relationship between them was plotted. The observed dependence, built on averaged points, is close to a power law, and, as one would expect, with an increase in the degree of oil recovery complexity, the oil recovery coefficient falls. The obtained estimates of the degree of oil recovery complexity allow us to rank different types of oils by their viscosity, density and reservoir permeability, which can be used to compare types of hard-to-recover oils by the value of the quality indicator. Methods to solve the problem of hard-to-remove high-viscosity and heavy oils should be aimed at reducing the viscosity of oil in the reservoir: injection of hot water / steam into the reservoir, the use of electric heaters, etc. Purpose. Assessment of the degree of oil recovery complexity and its impact on the efficiency of field development. The technique. The solution of the tasks set in the work was carried out on the method of mathematical statistics and the theory of fuzzy sets. In this case, the methods of processing the results, the correlation analysis, and the algorithm of fuzzy cluster analysis were used. Results. As a result of studies, 4 classes were obtained, each of which characterizes the degree of oil recovery complexity, a parameter was proposed for quantifying the degree of complexity, including oil density and viscosity, reservoir permeability, a relationship between this parameter and oil recovery coefficient was obtained. Scientific novelty. A classification of hard-to-recover reserves based on a fuzzy cluster analysis has been performed, and a parameter has been proposed for quantifying the degree of oil recovery complexity, a relationship has been obtained that allows judging the oil recovery by the degree of oil recovery complexity. Practical significance. The results obtained make it possible to classify hard-to-recover reserves and make decisions on the choice of methods for influencing the reservoir in various geological conditions.

HYDROGEOLOGICAL CHARACTERISTICS OF RESERVOIR WATERS OF THE CASPIAN SEA DEPOSITS

2021 ◽  
Vol 82 (3) ◽  
pp. 33-48
Author(s):  
NABIEVA VICTORIA V. ◽  
◽  
SEREBRYAKOV ANDREY O. ◽  
SEREBRYAKOV OLEG I. ◽  
◽  
...  
Keyword(s):  
Oil Recovery ◽  
Caspian Sea ◽  
Oil And Gas ◽  
Chemical Properties ◽  
Water Area ◽  
Water Soluble ◽  
Salt Composition ◽  
The Caspian Sea ◽  
Recovery Coefficient ◽  
Hydrogeological Characteristics

Hydrogeological conditions of reservoir waters of oil and gas fields in the northern water area of the Caspian Sea characterize the geological features of the structure of the Northern Caspian shelf, as well as the thermodynamic parameters of the exploitation of productive deposits, production and transportation of oil and gas. Reservoir waters contain water-soluble gases. According to the size of mineralization, the ratio of the main components of the salt composition, as well as the presence of iodine and bromine, reservoir waters can be attributed to a relatively "young" genetic age, subject to secondary geochemical processes of changing the salt composition in interaction with "secondary" migrated hydrocarbons. The physical and chemical properties of reservoir waters are determined by PVT analysis technologies. Hydrogeological and geochemical studies of compatibility with reservoir waters of marine waters injected to maintain reservoir pressures (PPD) during the development of offshore fields in order to increase the oil recovery coefficient (KIN) indicate the absence of colmating secondary sedimentation in mixtures of natural and man-made waters.

A Novel Double-Group Crosslinked Hydrogel with High Thixotropy for Water Control in Horizontal Wells

SPE Journal ◽  
2020 ◽  
pp. 1-15
Author(s):  
Gang Li ◽  
Lifeng Chen ◽  
Meilong Fu ◽  
Lei Wang ◽  
Yadong Chen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gelation Time ◽  
Horizontal Wells ◽  
Uniform Grid ◽  
Drilling Fluids ◽  
Water Production ◽  
Water Control ◽  
Recovery Coefficient ◽  
Metastable Structure ◽  
Control Water

Summary Horizontal wells that are completed with slotted liners often suffer from a severe water-production problem, which is detrimental to oil recovery. It is because the annulus between the slotted liners and wellbore cannot be fully filled with common hydrogels with poor thixotropy, which determines the ultimate hydrogel filling shape in the annulus. This paper presents a novel hydrogel with high thixotropy to effectively control water production in horizontal wells. This study is aimed at evaluating the thixotropic performance, gelation time, plugging performance, and degradation performance. The thixotropic performance of the new hydrogel was also investigated by measuring its rheological properties and examining its microstructures. It was found that the new hydrogel thickened rapidly after shearing. Its thixotropic recovery coefficient was 1.747, which was much higher than those of traditional hydrogels. The gelation time can be controlled in the range of 2 to 8 hours by properly adjusting the concentrations of the framework material, crosslinker, and initiator. The hydrogel could be customized for mature oil reservoirs, at which it was stable for more than 90 days. A series of laboratory physical modeling tests showed that the breakthrough pressure gradient and the plugging ratio of the hydrogel in sandpacks were higher than 9.5 MPa/m and 99%, respectively. At the same time, it was found that the hydrogel has good degradation properties; the viscosity of the hydrogel breaking solution was 4.22 mPa·s. Freeze-etching scanning-electron-microscopy examinations indicated that the hydrogel had a uniform grid structure, which can be broken easily by shear and restored quickly. This led to the remarkable thixotropic performance. The formation of a metastable structure caused by the electrostatic interaction and coordination effect was considered to be the primary reason for the high thixotropy. The successful development of the new thixotropic hydrogel not only helps to control water production from the horizontal wells, but also furthers the thixotropic theory of hydrogel. This study also provides technical guidelines for further increasing the thixotropies of drilling fluids, fracturing fluids, and other enhanced-oil-recovery polymers that are commonly used in the petroleum industry.

scholarly journals Evaluation of oil and gas potential of blocks A and B Song Hong basin and suggested exploration plan

2015 ◽  
Vol 18 (4) ◽  
pp. 12-31
Author(s):  
Luan Thi Bui
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Petroleum System ◽  
Basement Rock ◽  
3D Seismic ◽  
Oil Accumulation ◽  
Recovery Coefficient ◽  
Gas Accumulation ◽  
Risk Parameters ◽  
Gas Potential

Basing on the structure, stratigraphic, depositional conditions and petroleum system the petroleum prospect, Song Hong northern basin, particularly, blocks A and B was evaluated. SIgnificantly high gas potential areas are Hong Ha, Sapa and Bach Long Bac structural sections. Predominantly oil potential is found in Hau Giang and Vam Co Dong structural areas. Low gas potential is found in Cay Quat and Ben Hai structural sections and low oil potential is found in Vam Co Tay, Chi Linh, Do Son and Tien Lang structural areas. The result of the calculation of a petroleum accumulattion capacity at the local, enhanced recoveral volume, risk parameters for stored gas and oil amount in blocks A and B are the oil potential in Kainozoi basement rock (KZ): oil accumulation volume at the local is 1722.9 million barrels (273.9 million cubic meters); oil recovery coefficient is 0.25 %; oil recoverable amount is 430.7 million barrels (68.5 million cubic meters). The gas potential in Miocene structural areas: gas accumulation volume at the local is 1620 BSCF (45.8 billion cubic meters); gas recoverable amount is 972 BSCF (27.5 billion cubic meters). The coefficient of success is quite low at 0.18 - 0.31 for gas and 0.08 – 0.23 for oil. Suggestion for the exploitation and exploration in further steps is to servey the 3D seismic in a 1500 square kilometer area and drill 2 wells for the exploration.

Adsorption/Retention of Petroleum Sulfonates in Berea Cores

1977 ◽  
Vol 17 (05) ◽  
pp. 353-357 ◽  
Author(s):  
J.H. Bae ◽  
C.B. Petrick
Keyword(s):  
Adsorption Isotherm ◽  
Aqueous Solutions ◽  
Flow Rate ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Equivalent Weight ◽  
Flow Rates ◽  
The Core ◽  
Petroleum Sulfonate ◽  
Pass Through

Abstract A series of petroleum sulfonate adsorption experiments was conducted in 2-in.-diameter, 2-ft-long Berea cores initially saturated with 1-percent NaCl brine. The sulfonates used had an average equivalent weight of 430 with a broad equivalent-weight distribution. The concentration ranged from 0.01 to 8 per cent. The flow rates investigated ranged from 2 to 36 ft/D. Adsorption was determined either from analysis of the effluent concentrations or by extraction of sulfonates from the core. The physical properties of the solutions were also measured. In several tests, Na2CO3 was used as a sacrificial chemical, either in a preflood or added to the sulfonate solution. It was found that at certain concentrations, apparent adsorption is dependent on the flow rate. The sulfonate adsorption isotherm was found to pass through a maximum. The value of the pass through a maximum. The value of the adsorption maximum and the concentration at which it occurs are also dependent on the flow rate. The time required for adsorption equilibrium was found to increase with increasing sulfonate concentration. A sacrificial chemical reduced the sulfonate adsorption. However, sulfonate adsorption increased gradually with time. Adsorption tests should be conducted at realistic flow rates. Introduction One of the major problems in surfactant flooding is the adsorption of surfactants on the reservoir rock. If adsorption is excessive, surfactants are depleted rapidly from the slug as it moves through the reservoir; consequently, it loses the ability to lower the oil-water interfacial tension. Thus, the magnitude of adsorption is an important technical as well as economic parameter. It has been reported that the adsorption of petroleum sulfonates is selective. The high-equivalent-weight sulfonates are adsorbed preferentially whole low-equivalent-weight preferentially whole low-equivalent-weight sulfonates show almost no adsorption. Most of the adsorbed sulfonates had an equivalent weight of 500 or more. This type of fractionation was considered to be the main cause for poor oil recovery in a field pilot test. The literature data on the adsorption of petroleum sulfonates from aqueous solutions indicate petroleum sulfonates from aqueous solutions indicate that there is a maximum in the adsorption isotherm. Furthermore, the adsorption of sulfonate is reduced significantly when sacrificial chemicals are used. The experimental methods used in these measurements differ from one another and, on occasion, the adsorbed sulfonates are defined to be the amount extracted by a solvent after a brine flush. The term "adsorption" is used here rather loosely. Some people prefer the term retention to adsorption since there may be physical retention in a core. The physical retention may or may not exist in a given experiment and detection of it may be very difficult. The objective of this work is to investigate the adsorption phenomenon in dynamic core tests. Several questions are examined: How is the adsorption isotherm related to the general properties of the solution? Do the dynamic test conditions affect the adsorption measurement? Are sacrificial chemicals useful in reducing sulfonate adsorption? EXPERIMENTAL PROCEDURES The petroleum sulfonate used was a blend of sulfonates, TRS 18 and TRS 40 obtained from Witco Chemical Co., and has an average equivalent weight of 430. The equivalent weight ranged from 250 to 650, with about 80 percent ranging from 350 to 550, almost evenly distributed. Isopropyl alcohol was used as a cosolvent at 1/10 of the sulfonate concentration. A 1-percent NaCl brine was used as the aqueous medium. Weight percentage is used throughout this paper. All adsorption tests were conducted at room temperature of 72 degrees F in 2-in.-diameter, 2-ft-long Berea cores saturated with brine. The permeability to brine in all tests was 450 + 25 md. The sulfonate solution was injected continuously into the cores using a positive-displacement pump. The produced fluids were collected in a fraction collector. In most cases, at the end of sulfonate injection, the sulfonate in the core was extracted immediately with a methanol-chloroform mixture. SPEJ P. 353

scholarly journals The investigation of the average diameter of the SiO2 nanoparticles effect on the oil displacing efficiency from the pore in the rock formation using nanosuspension as a displacing agent

2022 ◽  
Vol 2150 (1) ◽  
pp. 012025
Author(s):  
A S Lobasov ◽  
A V Minakov
Keyword(s):  
Oil Recovery ◽  
Pure Water ◽  
Vertical Channel ◽  
Average Diameter ◽  
Sio2 Nanoparticles ◽  
Reynolds Numbers ◽  
Pore Channel ◽  
Computational Domain ◽  
Recovery Coefficient ◽  
Rock Formation

Abstract The numerical investigation of the nanofluid flow, which displaced the oil, in a microchannel was carried out. The effect of the average diameter of the SiO2 nanoparticles on the oil displacing efficiency by nanofluids for different sizes of microchannel at various Reynolds numbers was studied. A T-shaped microchannel with a vertical channel, called a pore channel, which imitated the pore in the rock formation was considered as a computational domain. The main flow channel width and height were 200 µm. The width and height of the pore channel were varied in the range from 100 µm to 800 µm. The Reynolds number varied from 0.1 to 100. The oil recovery coefficient, which is defined as the ratio of the displacing volume of oil from the pore to the volume of the pore was considered as the main studied characteristic. The nanofluid is considered a single-phase fluid with experimentally obtained properties. The mass concentration of SiO2 nanoparticles was 0.5%. The average diameters of nanoparticles were 5 nm, 18 nm, and 50 nm. It was found, that the oil recovery coefficient increased with a decrease in the average diameter of nanoparticles. It was obtained that the nanofluid can enhance the oil recovery several times compared to pure water.

Sign in / Sign up

Export Citation Format

Share Document