Technology Integration to Assess End-point Oil Saturation of the Relative Permeability Curves

2020 ◽  
Author(s):  
Mohammed Alghazal ◽  
Mohammed Alshakhs ◽  
Mohammed Bouaouaja
Keyword(s):  
Technology Integration ◽  
Relative Permeability ◽  
Oil Saturation ◽  
End Point ◽  
Relative Permeability Curves

Study on the Surfactant/Polymer Combination Flooding Relative Permeability Curves in Offshore Heavy Oil Reservoirs

2014 ◽  
Vol 887-888 ◽  
pp. 53-56 ◽  
Author(s):  
Wen Chao Jiang ◽  
Jian Zhang ◽  
Kao Ping Song ◽  
En Gao Tang ◽  
Bin Huang
Keyword(s):  
Relative Permeability ◽  
Heavy Oil ◽  
Great Influence ◽  
Water Flooding ◽  
Residual Oil ◽  
Experimental Conditions ◽  
Oil Saturation ◽  
Heavy Oil Reservoirs ◽  
Relative Permeability Curves ◽  
Associating Polymers

Different kinds of compound solutions were prepared by using different concentrations of hydrophobically associating polymers and sulfonate type surfactant. The static viscosity and interfacial tension of these solutions were measured. On the experimental conditions of the Suizhong 36-1 oilfield, the relative permeability curves of the water flooding and the surfactant/polymer combination flooding were measured through the constant speed unsteady method and the experimental data were processed through the way of J.B.N. The several existing kinds of viscosity processing methods of non-newtonian fluid were compared and analysed , and a new way is put forward . The results show that the relative permeability of the flooding phase is very low while displacing the heavy oil; the relative permeability of oil in combination flooding is higher than that in water flooding, the relative permeability of flooding phase in combination flooding is lower than that in water flooding and the residual oil saturation of combination flooding is lower than that of water flooding. Meanwhile, the concentrations of polymer and surfactant have a great influence on the surfactant/polymer combination relative permeability curves.

Experimental Study on Effect of Temperature on Heavy Steam/Oil Relative Permeability

2014 ◽  
Vol 522-524 ◽  
pp. 1562-1566
Author(s):  
Li Ping He ◽  
Ping Ping Shen ◽  
Qi Chao Gao ◽  
Meng Chen ◽  
Xiang Yang Ma
Keyword(s):  
High Precision ◽  
Relative Permeability ◽  
Water Saturation ◽  
Laboratory Simulation ◽  
Effect Of Temperature ◽  
Oil Saturation ◽  
Steam Flooding ◽  
Irreducible Water Saturation ◽  
Relative Permeability Curves ◽  
Base Data

Because of the instability of steam and tough requirement of HTHP equipments in steam flooding laboratory simulation, it is rather difficult to obtain representative Steam/Oil relative permeability curves with high precision. In addition, although the effect of temperature on Water/Oil relative permeability curves has been studied a lot both at home and aboard, there are still some controversy perspectives, and research on temperature effect on Steam/Oil relative permeability is rare. As to the above issue, an improved steam flooding experimental method is launched to obtain accurate base data, and then simplified JBN method is applied for data processing. The Result revealed that the improved experimental methods and simplified JBN formulas can obtain representative Steam/Oil relative permeability with high precision, and temperature affects steam/oil relative permeability in various aspects, as temperature increased, oil relative permeability and irreducible water saturation increased while steam relative permeability and residual oil saturation decreased.

Issue with Stone-II Three Phase Permeability Model, and A Novel Robust Fundamentals-Based Alternative to It

2021 ◽  
Author(s):  
Subodh Gupta
Keyword(s):  
Relative Permeability ◽  
Phase Flow ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Phase Permeability ◽  
Permeability Model ◽  
Oil Saturation ◽  
Three Phase ◽  
Three Phase Flow ◽  
Relative Permeability Curves

Abstract The objective of this paper is to present a fundamentals-based, consistent with observation, three-phase flow model that avoids the pitfalls of conventional models such as Stone-II or Baker's three-phase permeability models. While investigating the myth of residual oil saturation in SAGD with comparing model generated results against field data, Gupta et al. (2020) highlighted the difficulty in matching observed residual oil saturation in steamed reservoir with Stone-II and Baker's linear models. Though the use of Stone-II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears to counter-intuitively limit the flow of oil when water is present near its irreducible saturation. The current work begins with describing the problem with existing combinatorial methods such as Stone-II, which in turn combine the water-oil, and gas-oil relative permeability curves to yield the oil relative permeability curve in presence of water and gas. Then starting with the fundamentals of laminar flow in capillaries and with successive analogical formulations, it develops expressions that directly yield the relative permeabilities for all three phases. In this it assumes a pore size distribution approximated by functions used earlier in the literature for deriving two-phase relative permeability curves. The outlined approach by-passes the need for having combinatorial functions such as prescribed by Stone or Baker. The model so developed is simple to use, and it avoids the unnatural phenomenon or discrepancy due to a mathematical artefact described in the context of Stone-II above. The model also explains why in the past some researchers have found relative permeability to be a function of temperature. The new model is also amenable to be determined experimentally, instead of being based on an assumed pore-size distribution. In that context it serves as a set of skeletal functions of known dependencies on various saturations, leaving constants to be determined experimentally. The novelty of the work is in development of a three-phase relative permeability model that is based on fundamentals of flow in fine channels and which explains the observed results in the context of flow in porous media better. The significance of the work includes, aside from predicting results more in line with expectations and an explanation of temperature dependent relative permeabilities of oil, a more reliable time dependent residual oleic-phase saturation in the context of gravity-based oil recovery methods.

Capillary Pressure Effects on Estimating the Enhanced-Oil-Recovery Potential During Low-Salinity and Smart Waterflooding

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 481-496 ◽  
Author(s):  
Pål Østebø Andersen
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Low Salinity ◽  
Smart Water ◽  
Relative Permeability Curves

Summary Many experimental studies have investigated smart water and low-salinity waterflooding and observed significant incremental oil recovery after changes in the injected-brine composition. The common approach to model such enhanced-oil-recovery (EOR) mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness can retain much oil at the outlet of the flooded core because of the capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in highly permeable cores at typical laboratory rates. Injecting a brine that changes the wetting state to less-oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation. This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing coreflooding that accounts for wettability changes caused by changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability-alteration (WA) component coupled to the shifting of relative permeability curves and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically because of the changing of one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and the magnitude of capillary end effects can be reduced because of increased water-wetness or because of a reduction in water relative permeability giving a greater viscous drag on the oil.

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

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