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.

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

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

Estimation of dynamic petrophysical properties of water-bearing sands invaded with oil-base mud from the interpretation of multiple borehole geophysical measurements

Geophysics ◽  
2012 ◽  
Vol 77 (6) ◽  
pp. D209-D227 ◽  
Author(s):  
Zoya Heidari ◽  
Carlos Torres-Verdín
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Radial Distribution ◽  
Apparent Resistivity ◽  
Water Saturation ◽  
Estimation Method ◽  
Petrophysical Properties ◽  
Fluid Saturation ◽  
Irreducible Water Saturation ◽  
Geophysical Measurements

Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.

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.

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.

Transport of CO2-Foaming Agents During CO2-Foam Processes in Fractured Chalk Rock

2010 ◽  
Vol 13 (04) ◽  
pp. 710-719 ◽  
Author(s):  
John Zuta ◽  
Ingebret Fjelde
Keyword(s):  
Water Saturation ◽  
Computer Modelling ◽  
Transport Rate ◽  
Residual Oil ◽  
Oil Saturation ◽  
Foaming Agent ◽  
Foaming Agents ◽  
Residual Oil Saturation ◽  
Co2 Foam ◽  
The Matrix

Summary The coinjection of carbon dioxide (CO2) and a CO2-foaming agent to form stable CO2 foam has been found to improve the sweep efficiency during CO2-foam processes in carbonate reservoirs. However, only a few studies of CO2-foam transport in fractured rock have been reported. In fractured chalk reservoirs with low matrix permeability, the aqueous CO2-foaming-agent solution will flow mainly through the fractures. The total retention of the CO2-foaming agent in the reservoir will depend on how much of the matrix is contacted by the CO2-foaming-agent solution during the project period and, therefore, on its transport rate into the matrix. This paper presents results from a series of static and flowthrough experiments carried out to investigate the transport and retention phenomena of CO2-foaming agents in fractured chalk models at 55°C. Fractured chalk models with 100% water-saturation and residual-oil saturation after waterflooding were used. In the static experiments, the fractured model was created by transferring core plugs with different diameters into steel cells with an annulus space around the plugs. The fracture volume was filled with foaming-agent solutions with different initial concentrations. The experiments were carried out in parallel, with liquid samples regularly taken out from the fracture above the plugs and analyzed for the foaming-agent concentration. The experiments were monitored until the concentrations in the fractures reached a plateau. At specific and constant concentrations of the foaming agent in the fractures, the plugs were demounted and samples drilled out along the whole lengths of the plugs from the outer, middle, and center portions. These samples were analyzed for foaming-agent concentration to determine how much of it had penetrated the matrix. Results indicate that the transport of the foaming-agent decreases toward the center of the plugs with 100% water-saturation and residual-oil saturation after waterflooding. Modeling of the static experiments using the Computer Modelling Group (CMG)'s commercial reservoir simulator STARS was also carried out to determine the transport rate for the foaming agent. A good history match between experimental and modeling results was obtained. In the flow-through experiments, the fractured model was created by drilling a concentric hole through the center of the plug. The hole, simulating an artificial fracture, was filled with glass beads of different dimensions. Fractured models with different effective permeability were flooded with equal volumes of the foaming-agent solution. Results show that the transport of CO2-foaming agent into the matrix is slower in the fractured models than in the homogeneous models with viscous flooding of the rock.

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