Drainage and Imbibition CO2/Brine Relative Permeability Curves at Reservoir Conditions for High-Permeability Carbonate Rocks

2010 ◽  
Author(s):  
Douglas Brant Bennion ◽  
Stefan Bachu
Keyword(s):  
Relative Permeability ◽  
Carbonate Rocks ◽  
High Permeability ◽  
Reservoir Conditions ◽  
Relative Permeability Curves

scholarly journals Assessment of xanthan gum and xanthan-g-silica derivatives as chemical flooding agents and rock wettability modifiers

2020 ◽  
Vol 75 ◽  
pp. 12 ◽  
Author(s):  
Ahmed Ashraf Soliman ◽  
Abdelaziz Nasr El-hoshoudy ◽  
Attia Mahmoud Attia
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Xanthan Gum ◽  
Water Saturation ◽  
Chemical Characterization ◽  
Spectroscopic Methods ◽  
Chemical Flooding ◽  
Reservoir Conditions ◽  
Relative Permeability Curves ◽  
Underground Reservoirs

Currently, biomolecules flooding in the underground reservoirs acquires sustainable interest owing to their availability and eco-friendly properties. The current study reported chemical displacement by xanthan gum as well as xanthan/SiO2 and xanthan grafted with vinylsilane derivatives. Chemical characterization evaluated by traditional spectroscopic methods. Investigation of fluids response to reservoir environment assessed through rheological performance relative to shearing rate, ionic strength, and thermal stability. A sequence of flooding runs generated on 10 sandstone outcrops with different porosity and permeabilities. Core wetness assessed through relative permeability curves at different water saturation. The flooding tests indicate that grafting of the silica derivative overcome the shortage of xanthan solution in flooding operations relative to the reservoir conditions. The ability of the flooding solutions to alter rock wettability explored through relative permeability curves at different water saturation. The results reveal that the synthesized composite was a promised agent for enhancing oil recovery and profile conformance.

scholarly journals Quantifying the Low Salinity Waterflooding Effect

Energies ◽  
2021 ◽  
Vol 14 (7) ◽  
pp. 1979
Author(s):  
Omar Chaabi ◽  
Mohammed Al Kobaisi ◽  
Mohamed Haroun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Laboratory Scale ◽  
Residual Oil ◽  
Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Reservoir Conditions ◽  
Salinity Water ◽  
Relative Permeability Curves

Low salinity waterflooding (LSW) has shown promising results in terms of increasing oil recovery at laboratory scale. In this work, we study the LSW effect, at laboratory scale, and provide a basis for quantifying the effect at field scale by extracting reliable relative permeability curves. These were achieved by experimental and numerical interpretation of laboratory core studies. Carbonate rock samples were used to conduct secondary and tertiary unsteady-state coreflooding experiments at reservoir conditions. A mathematical model was developed as a research tool to interpret and further validate the physical plausibility of the coreflooding experiments. At core scale and a typical field rate of ~1 ft/day, low salinity water (LS) resulted in not only ~20% higher oil recovery compared to formation water (FW) but also recovered oil sooner. LS water also showed capability of reducing the residual oil saturation when flooded in tertiary mode. The greater oil recovery caused by LSW can be attributed to altering the wettability of the rock to less oil-wet as confirmed by the numerically extracted relative permeability curves.

scholarly journals Variations in Permeability and Porosity of Synthetic Oil Reservoir Rock-Methods of Control

1965 ◽  
Vol 5 (04) ◽  
pp. 329-332 ◽  
Author(s):  
Larman J. Heath
Keyword(s):  
Porous Media ◽  
Relative Permeability ◽  
Reservoir Rock ◽  
Oil Reservoir ◽  
Natural Reservoir ◽  
Natural Rock ◽  
Unconsolidated Sand ◽  
Synthetic Rock ◽  
Porosity And Permeability ◽  
Relative Permeability Curves

Abstract Synthetic rock with predictable porosity and permeability bas been prepared from mixtures of sand, cement and water. Three series of mixes were investigated primarily for the relation between porosity and permeability for certain grain sizes and proportions. Synthetic rock prepared of 65 per cent large grains, 27 per cent small grains and 8 per cent Portland cement, gave measurable results ranging in porosity from 22.5 to 40 per cent and in permeability from 0.1 darcies to 6 darcies. This variation in porosity and permeability was caused by varying the amount of blending water. Drainage- cycle relative permeability characteristics of the synthetic rock were similar to those of natural reservoir rock. Introduction The fundamental behavior characteristics of fluids flowing through porous media have been described in the literature. Practical application of these flow characteristics to field conditions is too complicated except where assumptions are overly simplified. The use of dimensionally scaled models to simulate oil reservoirs has been described in the literature. These and other papers have presented the theoretical and experimental justification for model design. Others have presented elements of model construction and their operation. In most investigations the porous media have consisted of either unconsolidated sand, glass beads, broken glass or plastic-impregnated granular substances-materials in which the flow behavior is not identical to that in natural reservoir rock. The relative permeability curves for unconsolidated sands differ from those for consolidated sandstone. The effect of saturation history on relative permeability measurements A discussed by Geffen, et al. Wygal has shown quite conclusively that a process of artificial cementation can be used to render unconsolidated packs into synthetic sandstones having properties similar to those of natural rock. Many theoretical and experimental studies have been made in attempts to determine the structure and properties of unconsolidated sand, the most notable being by Naar and Wygal. Others have theorized and experimented with the fundamental characteristics of reservoir rocks. This study was conducted to determine if some general relationship could be established between the size of sand grains and the porosity and permeability in consolidated binary packs. This paper presents the results obtained by changing some of the factors which affect the porosity and permeability of synthetically prepared sandstone. In addition, drainage relative permeability curves are presented. EXPERIMENTAL PROCEDURE Mixtures of Portland cement with water and aggregate generally are designed to have certain characteristics, but essentially all are planned to be impervious to water or other liquids. Synthetic sandstone simulating oil reservoir rock, however, must be designed to have a given permeability (sometimes several darcies), a porosity which is primarily the effective porosity but quantitatively similar to natural rock, and other characteristics comparable to reservoir rock, such as wettability, pore geometry, tortuosity, etc. Unconsolidated ternary mixtures of spheres gave both a theoretically computed and an experimentally observed minimum porosity of about 25 per cent. By using a particle-distribution system, one-size particle packs had reproducible porosities in the reproducible range of 35 to 37 per cent. For model reservoir studies of the prototype system, a synthetic rock having a porosity of 25 per cent or less and a permeability of 2 darcies was required. The rock bad to be uniform and competent enough to handle. Synthetic sandstone cores mere prepared utilizing the technique developed by Wygal. Some tight variations in the procedure were incorporated. The sand was sieved through U.S. Standard sieves. SPEJ P. 329ˆ

Analytical Solutions and Derivation of Relative Permeabilities for Water-Heavy Oil Displacement and Gas-Heavy Oil Gravity Drainage Under Non-Isothermal Conditions

2016 ◽  
Vol 19 (01) ◽  
pp. 181-191 ◽  
Author(s):  
F. J. Argüelles-Vivas ◽  
T.. Babadagli
Keyword(s):  
Temperature Gradient ◽  
Relative Permeability ◽  
Heavy Oil ◽  
Variable Temperature ◽  
Spontaneous Imbibition ◽  
Analytical Models ◽  
Gravity Drainage ◽  
Positive Temperature ◽  
Relative Permeability Curves ◽  
Isothermal Gas

Summary Analytical models were developed for non-isothermal gas/heavy-oil gravity drainage and water-heavy oil displacements in round capillary tubes including the effects of a temperature gradient throughout the system. By use of the model solution for a bundle of capillaries, relative permeability curves were generated at different temperature conditions. The results showed that water/gas-heavy oil interface location, oil-drainage velocity, and production rate depend on the change of oil properties with temperature. The displacement of heavy oil by water or gas was accelerated under a positive temperature gradient, including the spontaneous imbibition of water. Relative permeability curves were greatly affected by temperature gradient and showed significant changes compared with the curves at constant temperature. Clarifications were made as to the effect of variable temperature compared with the constant (but high) temperatures throughout the bundle of capillaries.

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