The Effect of Temperature on Relative and Absolute Permeability of Sandstones

1975 ◽  
Vol 15 (05) ◽  
pp. 376-384 ◽  
Author(s):  
R.M. Weinbrandt ◽  
H.J. Ramey ◽  
F.J. Casse
Keyword(s):  
Relative Permeability ◽  
Temperature Increase ◽  
Absolute Permeability ◽  
Effect Of Temperature ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Permeability Ratio ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Individual

MEMBERS SPE-AIME Abstract Equipment was constructed to perform dynamic displacement experiments on small core samples under conditions of elevated temperature. Oil-water flowing fraction and pressure drop were recorded continuously for calculation of both the relative permeability ratio and the individual relative permeability ratio and the individual relative permeabilities. Imbibition relative permeabilities permeabilities. Imbibition relative permeabilities were measured for five samples of Boise sandstone at room temperature and at 175deg.F. The fluids used were distilled water and a white mineral oil. The effect of temperature on absolute permeability was investigated for six Boise sandstone samples and two Berea sandstone samples. Results for all samples were similar. The irreducible water saturation increased significantly, while the residual oil saturation decreased significantly with temperature increase. The individual relative permeability to oil increased for all water saturations below the room-temperature residual oil saturation, but the relative permeability to water at flood-out increased with permeability to water at flood-out increased with temperature increase. Absolute permeability decreased with temperature increase. Introduction Test environment is generally acknowledged to have a significant effect on measurement of relative permeability. The environment consists not only permeability. The environment consists not only of the temperature and pressure, but also of the fluids used and the core condition. Several workers have used the approach of completely simulating the reservoir conditions in the laboratory experiment. Such methods are termed "restored state." Restored state data are generally different from "room condition" data; since several variables are involved, it is difficult to determine the importance of each variable. Another approach used attributes the changes in relative permeability to changes in the rock-fluid interaction or wettability. Wettability, however, depends on many variables. Specifically, wettability depends on the composition of the rock surface, the composition of the fluids, the saturation history of the rock surface, and the temperature and pressure of the system. The purpose of this study is to isolate temperature as a variable in the relative permeability of a given rock-fluid system. Work on isolation of temperature as a variable in relative permeability has been conducted since the early 1960s. Edmondsons established results in 1965 for a Berea sandstone core using both water/refined oil and water/crude oil as fluid pairs. He showed a change in the relative permeability ratio accompanied by a decrease in the residual oil saturation with temperature increase. Edmondson showed no data for water saturations below 40 percent, and his curves show considerable scatter in the middle saturation ranges. Edmondson's work was the only study to use consolidated cores to investigate the effect of temperature on relative permeability measurements. Poston et al. presented waterflood data for sand packs containing 80-, 99-, a nd 600-cp oil, and packs containing 80-, 99-, a nd 600-cp oil, and observed an increase in the individual relative permeabilities with temperature increase. The permeabilities with temperature increase. The increase in the oil and the water permeability was accompanied by an increase in irreducible water saturation and a decrease in the residual oil saturation with temperature increase. Poston et al. was the only work to present individual oil and water permeability. Davidsons presented results for displacement of No. 15 white oil from a sand pack by distilled water, steam, or nitrogen. However, he found little permeability-ratio dependence in the middle permeability-ratio dependence in the middle saturation ranges. Davidson, too, found a decrease in the residual oil saturation with temperature increase, but he did not include data on irreducible water saturation. SPEJ P. 376

Validation of Gravity-dominated Relative Permeability and Residual Oil Saturation in a Giant Oil Reservoir

1998 ◽  
Author(s):  
J.T. Edwards ◽  
M.M. Honarpour ◽  
R.D. Hazlett ◽  
M. Cohen ◽  
A. Membere ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Oil Reservoir ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation

Thermal Stability of Surfactants for Reservoir Application (includes associated papers 11323 and 11597 )

1982 ◽  
Vol 22 (05) ◽  
pp. 722-730 ◽  
Author(s):  
L.L. Handy ◽  
J.O. Amaefule ◽  
V.M. Ziegler ◽  
I. Ershaghi
Keyword(s):  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Half Life ◽  
Elevated Temperatures ◽  
Effect Of Temperature ◽  
Residual Oil ◽  
Chemical Additives ◽  
Thermal Stabilities ◽  
Oil Saturation ◽  
Residual Oil Saturation

Abstract The thermal stabilities of several sulfonate surfactantsand one nonionic surfactant have been evaluated. Thedecomposition reactions have been observed to followfirst-order kinetics. Consequently, a quantitativemeasure of a surfactant's stability at a given temperatureis its half-life. Furthermore, the activation energy can beestimated from rate data obtained at two or moretemperatures. This permits limited extrapolation of theobserved decomposition rates to lower temperatures forwhich the rates are too low for convenient measurement.The surfactants we investigated are being considered forsteamflood additives and need to be relatively stable atsteam temperatures.None of the surfactants evaluated to date has therequisite stability for use in steamfloods. The most stablepetroleum sulfonate we have investigated has a half-lifeof 11 days at 180 degrees C (356 degrees F). With this half-life, substantial overdosing would be required tomaintain the minimum effective surfactant concentration forthe life of the flood. On the other hand, the estimatedhalflife for this surfactant at 93 degrees C (200 degrees F), calculated by extrapolation, would be 33 years.Tests with the nonionic surfactant, nonylphenoxy-polyethanol, have shown this material to have a very short half-life at steam temperatures, but it doesappear to be more stable at concentrations greater than thecritical micelle concentration(CMC). In limited tests, the sulfonates showed increased stability in the presenceof a 2-M salt solution. Introduction Several chemical additives are being considered for usewith steamfloods to reduce the producing steam/oilratios and to increase oil recovery from steam projects.The emphasis to date has been on inorganic chemicaladditives. Sodium hydroxide has been used in the fieldwithout success. We have been investigating thepotential benefits of using organic surfactants. This hasbeen discusssed recently by Brown et al. and byGopalakrishnan et al. The surfactant would be introducedinto the reservoir along, with the steam at the beginning ofthe steamflood and, possibly, intermittently during the floodprocess. The surfactant would be injected in diluteconcentrations and would be expected to travel in thatportion of the reservoir being flooded by hot water.Although the residual oil saturation in the steam zone has been observed to be very low, residual saturation in thehot water portion of the steamflood is expected to be thenormal waterflood residual. A surfactant in the hot watermay reduce this residual oil saturation. A synergistic effect could be observed between the surfactant and thetemperature to give better performance than would beobserved for a surfactant flood at normal reservoirtemperatures.For the process to work as anticipated, the surfactantmust move in the heated portion of the reservoir, and it must be sufficiently stable at elevated temperatures tofunction as an effective recovery agent for the life of theflood. Therefore, two aspects of the process are beingstudied simultaneously. One of these is the effect oftemperature on adsorption of the surfactants, and theother is the effect of heat on the stability of thesurfactants. The effect of temperature on adsorption will bediscussed in a later paper. The objective of this paper isto discuss the experimental evaluation of the thermalstability of some surfactant types that could haveapplication in reservoir floods. The effect of temperatureon adsorption and stability of these surfactants also willbe important in micellar floods at higher reservoirtemperatures. Experimental Procedures Several anionic and noninoic surfactants were selectedfor evaluation. SPEJ P. 722^

scholarly journals A New Measurement of Anisotropic Relative Permeability and Its Application in Numerical Simulation

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 4731
Author(s):  
Congcong Li ◽  
Shuoliang Wang ◽  
Qing You ◽  
Chunlei Yu
Keyword(s):  
Numerical Simulation ◽  
Relative Permeability ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Two Phase ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Displacement Direction ◽  
Oil Water ◽  
The Law

In this paper, we used a self-developed anisotropic cubic core holder to test anisotropic relative permeability by the unsteady-states method, and introduced the anisotropic relative permeability to the traditional numerical simulator. The oil–water two-phase governing equation considering the anisotropic relative permeability is established, and the difference discretization is carried out. We formed a new oil–water two-phase numerical simulation method. It is clear that in a heterogeneous rock with millimeter to centimeter scale laminae, relative permeability is an anisotropic tensor. When the displacement direction is parallel to the bedding, the residual oil saturation is high and the displacement efficiency is low. The greater the angle between the displacement direction and the bedding strike, the lower the residual oil saturation is, the higher the displacement efficiency is, and the relative permeability curve tends towards a rightward shift. The new simulator showed that the anisotropic relative permeability not only affects the breakthrough time and sweep range of water flooding, but also has a significant influence on the overall water cut. The new simulator is validated with the actual oilfield model. It could describe the law of oil–water seepage in an anisotropic reservoir, depict the law of remaining oil distribution of a typical fluvial reservoir, and provide technical support for reasonable injection-production directions.

An Approach for Exploring the Application of the Flow Zone Index Concept in Describing Petrophysical Properties Using Available SCAL Data Relative Permeability

2021 ◽  
Author(s):  
Efeoghene Enaworu ◽  
Tim Pritchard ◽  
Sarah J. Davies
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Petrophysical Properties ◽  
Residual Oil ◽  
Flow Zone ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Core Samples ◽  
Irreducible Water Saturation ◽  
Permeability Data

Abstract This paper describes a unique approach for exploring the Flow Zone Index (FZI) concept using available relative permeability data. It proposes an innovative routine for relating the FZI parameter to saturation end-points of relative permeability data and produces a better model for relative permeability curves. In addition, this paper shows distinct wettabilities for various core samples and validated functions between FZI and residual oil saturation (Sor), irreducible water saturation (Swi), maximum oil allowed to flow (Kro, max), maximum water allowed to flow (Krw, max),and mobile/recoverable oil (100-Swi-Sor). The wettability of the core samples were defined using cross-plots of relative permeability of oil (Kro), relative permeability of water (Krw), and water saturation (Sw). After classifying the data sets into their respective wettabilities based on these criteria, a stepwise non-linear regression analysis was undertaken to develop realistic correlations between the FZI parameter, initial water saturation and end-point relative permeability parameters. In addition, a correlation using Corey's type generalised model was developed using relative permeability data, with new power law constants and well defined curves. Other parameters, including Sor, Swi, Kro, max, Krw,max and mobile oil, were plotted against FZI and correlations developed for them showed unique well behaved plots with the exception of the Sor plot. A possible theory to explain this unexpected behaviour of the FZI Vs Sor cross plot was noted and discussed. These derived functions and established relationships between the FZI term and other petrophysical parameters such as permeability, porosity, water saturation, relative permeability and residual oil saturation can be applied to other wells or reservoir models where these key parameters are already known or unknown. These distinctive established correlations could be employed in the proper characterization of a reservoir as well as predicting and ground truthing petrophysical properties.

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.

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