THE IMPORTANCE OF WETTABILITY AND WETTABILITY TESTING METHODS USED IN THE OIL INDUSTRY

1995 ◽  
Vol 35 (1) ◽  
pp. 143 ◽  
Author(s):  
S.R.J. Clinch ◽  
P.J. Boult ◽  
R.A. Hayes
Keyword(s):  
Oil Recovery ◽  
Rock Strength ◽  
Pore Space ◽  
Oil Industry ◽  
Petroleum Reservoir ◽  
Pressure Data ◽  
Reservoir Conditions ◽  
Recent Method ◽  
Production Problems

The wettability of a petroleum reservoir governs the location of fluids within its pore space and hence the movement of fluids through it during production. Properties that may be affected by wettability include resistivity, capillary pressure, relative permeability and rock strength as well as behaviour during waterflood and enhanced oil recovery. Generally every reservoir is initially assumed to be water wet. When production problems arise, the wettability of a reservoir will only be questioned when all other possibilities have been accounted for. By correctly determining the wettability of a reservoir more accurate models can be provided for reservoir simulation, which in turn will improve the prediction of future field performance.Many methods of varying difficulty and accuracy can be used to measure wettability. However, they can only be as good as the quality of the fluid samples used. It is important to understand that reliable results are only obtained when sample contamination is minimised and experimental control is maximised. Some wettability experiments can be carried out at reservoir conditions, which may be more representative, but also more susceptible to contamination.In an oil reservoir either oil or brine can be the most wetting phase and gas is normally the least wetting phase. From a thorough investigation of downhole logs and production data it may be possible to identify wetting anomalies. Examining formation pressure data is the most recent method proposed for determining wettability.

Bulk Modulus of Hydrocarbon Fluids After Injection with Supercritical CO2 at Reservoir Conditions

2021 ◽  
Author(s):  
Mohamed Eid Kandil
Keyword(s):  
Mechanical Properties ◽  
Bulk Modulus ◽  
Supercritical Co2 ◽  
Pore Space ◽  
Fluid Phase ◽  
Petroleum Reservoir ◽  
Fluid Mixture ◽  
Mixture Density ◽  
Well Completion ◽  
Reservoir Conditions

Abstract The mechanical properties of hydrocarbon reservoirs significantly depend on the elastic properties of the fluids occupying the pore space in the rock frame. Accurate data and models for the mechanical properties of fluid mixtures in a petroleum reservoir containing supercritical CO2 should be available at the same reservoir conditions for reliable design of well-completion, maximizing reservoir productivity, and minimizing risk in drilling operations. This work investigates the change in the bulk modulus of the higher hydrocarbon fluid (decane C10H22) after the injection with supercritical CO2 at reservoir conditions. The isothermal bulk modulus βT of liquids under pressure, simply defined as the first-order derivative of pressure with respect to volume, is determined in this study from the derivative of pressure with respect to density. The density data were obtained from experimental measurements of mixtures of supercritical CO2 + C10H22 for a range of CO2 mole fractions from 0 to 0.73, at temperatures from 40 to 137 °C and pressures up to 12000 psi. The isothermal derivative coefficients of the pressure as a function of density are reported for each CO2 concentration measured in this work. Common fluid-substitution models, including the Gassmann model, which is only valid for the isothermal regime, have limited predictive power because most fluids are treated as simple fluids, with their mechanical properties only characterized by their densities. However, under different environments, such as when supercritical CO2 is injected into the geological formation, the fluid phase and its mechanical properties can vary dramatically. At high pressure, the density of CO2 can equal to that of the hydrocarbon phase ρ(CO2)/ρ(C10H22) ≈ 1, while the bulk modulus of CO2 remains as low as only βT(CO2)/βT(C10H22) ≈ 7 %. Excessive decrease in the bulk modulus can easily cause subsidence, although the pore pressure and the fluid mixture density remain unchanged, even at pressures up to 4000 psi.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

Miscible Flooding for Bitumen Recovery with a Novel Solvent

2021 ◽  
Author(s):  
Tanya Ann Mathews ◽  
Alex J.Cortes ◽  
Richard Bryant ◽  
Berna Hascakir
Keyword(s):  
Oil Recovery ◽  
Cold Water ◽  
Pore Space ◽  
Oil Quality ◽  
Environmental Concerns ◽  
Solvent Recovery ◽  
Core Flooding ◽  
Recovery Method ◽  
Steam Flooding ◽  
Oil Emulsions

Abstract Steam injection is an effective heavy oil recovery method, however, poses several environmental concerns. Solvent injection methods are introduced in an attempt to combat these environmental concerns. This paper evaluates the effectiveness of a new solvent (VisRed) in the recovery of a Canadian bitumen and compares its results with toluene. While VisRed is selected due to its high effectiveness as a viscosity reducer even at very low concentrations, toluene is selected due to its high solvent power. Five core flooding experiments were conducted; E1 (Steam flooding), E2 (VisRed flooding), E3 (Toluene flooding), E4 (Steam + Toluene flooding), and E5 (Steam + VisRed flooding). Core samples were prepared by saturating 60% of the pore space with oil samples and 40% with deionized water. The solvents were injected at a 2 ml/min rate, while steam was injected at a 18 ml/min cold water equivalent rate. Produced oil and water samples were collected every 20 min during every experiment. The oil recovery efficiencies of the core flood experiments were analyzed by the emulsion characterization in the produced fluids and the residual oil analysis on the spent rock samples. The best oil recovery of ~30 vol % was obtained for E2 (VisRed) in which VisRed was injected alone. Although similar cumulative recoveries were obtained both for E2 (VisRed) and E3 (Toluene), the amount of VisRed injected [~1 pore volumes (PV)] was half the volume required by toluene (~2 PV). The produced oil quality variations are mainly due to the formation of the water-in-oil emulsions during mainly steam processes (E1, E4, and E5). The increased amount of the polar fractions in the produced oil enhances the formation of the emulsions. These polar fractions are namely asphaltenes and resins. As the amount of the polar fractions in the produce oil increases, more water-in-oil emulsion formation is observed due to the polar-polar interaction between crude oil fractions and water. Consequently, E1 and E5 resulted in more water in oil emulsions. The cost analysis also shows the effectiveness of solvent recovery over steam-solvent recovery processes.

Application of Hybrid Biosystems for Stimulation of Oil Production

2021 ◽  
Author(s):  
Baghir Alakbar Suleimanov ◽  
Sabina Jahangir Rzayeva ◽  
Ulviyya Tahir Akhmedova
Keyword(s):  
Oil Recovery ◽  
Single Phase ◽  
Experimental Studies ◽  
Oil Production ◽  
Pore Channel ◽  
Subcritical Region ◽  
Slippage Effect ◽  
Liquid Systems ◽  
Reservoir Conditions

Abstract Microbial enhanced oil recovery is considered to be one of the most promising methods of stimulating formation, contributing to a higher level of oil production from long-term fields. The injection of bioreagents into a reservoir results in the creation of oil-dicing agents along with significant amount of gases, mainly carbon dioxide. In early, the authors failed to study the preparation of self-gasified biosystems and the implementation of the subcritical region (SR) under reservoir conditions. Gasified systems in the subcritical phase have better oil-displacing properties than non-gasified systems. The slippage effect determines the behavior of gas–liquid systems in the SR under reservoir conditions. Slippage occurs more easily when the pore channel has a smaller average radius. Therefore, in a heterogeneous porous medium, the filtration profile of gasified liquids in the SR should be more uniform than for a degassed liquid. The theoretical and practical foundations for the preparation of single-phase self-gasified biosystems and the implementation of the SR under reservoir conditions have been developedSR under reservoir conditions. Based on experimental studies, the superior efficiency of oil displacement by gasified biosystems compared with degassed ones has been demonstrated. The possibility of efficient use of gasified hybrid biopolymer systems has been shown.

Laboratory studies of oil-washing characteristics of surfactants in the pore space of reservoir rocks

2021 ◽  
pp. 86-98
Author(s):  
V. Yu. Ogoreltsev ◽  
S. A. Leontiev ◽  
A. S. Drozdov
Keyword(s):  
Oil Recovery ◽  
Pore Space ◽  
Oil Field ◽  
Oil Fields ◽  
Molecular Surface ◽  
Laboratory Studies ◽  
Reservoir Rocks ◽  
Technological Efficiency ◽  
Chemical Eor ◽  
Physical And Chemical

When developing hard-to-recover reserves of oil fields, methods of enhanced oil recovery, used from chemical ones, are massively used. To establish the actual oil-washing characteristics of surfactant grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory studies was carried out, including the study of molecular-surface properties upon contact of oil from the BS10 formation of the West Surgutskoye field and model water types with the addition of surfactants of various concentrations, as well as filtration tests of surfactant technology compositions on core models of the VK1 reservoir of the Rogozhnikovskoye oil field. On the basis of the performed laboratory studies of rocks, it has been established that conducting pilot operations with the use of Neonol RHP-20 will lead to higher technological efficiency than from the currently used at the company's fields in the compositions of the technologies of physical and chemical EOR Neonol BS-1 and proposed for application of Neftenol VKS, Aldinol-50 and Betanol.

Oil emulsion characteristics as significance in efficiency forecast of oil-displacing formulations based on surfactants

2021 ◽  
pp. 91-107
Author(s):  
E. A. Turnaeva ◽  
E. A. Sidorovskaya ◽  
D. S. Adakhovskij ◽  
E. V. Kikireva ◽  
N. Yu. Tret'yakov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Concentration ◽  
Chemical Flooding ◽  
Optimal Salinity ◽  
Oil Emulsion ◽  
Oil Displacement ◽  
Laboratory Selection ◽  
Reservoir Conditions ◽  
Selection Of ◽  
Comprehensive Study

Enhanced oil recovery in mature fields can be implemented using chemical flooding with the addition of surfactants using surfactant-polymer (SP) or alkaline-surfactant-polymer (ASP) flooding. Chemical flooding design is implemented taking into account reservoir conditions and composition of reservoir fluids. The surfactant in the oil-displacing formulation allows changing the rock wettability, reducing the interfacial tension, increasing the capillary number, and forming an oil emulsion, which provides a significant increase in the efficiency of oil displacement. The article is devoted with a comprehensive study of the formed emulsion phase as a stage of laboratory selection of surfactant for SP or ASP composition. In this work, the influence of aqueous phase salinity level and the surfactant concentration in the displacing solution on the characteristics of the resulting emulsion was studied. It was shown that, according to the characteristics of the emulsion, it is possible to determine the area of optimal salinity and the range of surfactant concentrations that provide increased oil displacement. The data received show the possibility of predicting the area of effectiveness of ASP and SP formulations based on the characteristics of the resulting emulsion.

Self-gasified biosystems for enhanced oil recovery

2021 ◽  
pp. 2150274
Author(s):  
B. A. Suleimanov ◽  
S. J. Rzayeva ◽  
U. T. Akhmedova
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Experimental Studies ◽  
Microbial Enhanced Oil Recovery ◽  
Heterogeneous Porous Medium ◽  
Oil Displacement ◽  
Subcritical Region ◽  
Reservoir Conditions

Microbial enhanced oil recovery is considered to be one of the most promising methods of stimulating formation, contributing to a higher level of oil production from long-term fields. The injection of bioreagents into a reservoir results in the creation of oil-displacing agents along with a significant amount of gases, mainly carbon dioxide. Earlier, the authors failed to study the preparation of self-gasified biosystems and the implementation of the subcritical region (SR) under reservoir conditions. Gasified systems in the subcritical phase have better oil-displacing properties than nongasified systems. In a heterogeneous porous medium, the filtration profile of gasified liquids in the SR should be more uniform than for a degassed liquid. Based on experimental studies, the superior efficiency of oil displacement by gasified biosystems compared with degassed ones has been demonstrated. The possibility of efficient use of gasified hybrid biopolymer systems has been shown.

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