Effect of Temperature on Oil/Water Relative Permeabilities of Unconsolidated and Consolidated Sands

1985 ◽  
Vol 25 (06) ◽  
pp. 945-953 ◽  
Author(s):  
Mark A. Miller ◽  
H.J. Ramey

Abstract Over the past 20 years, a number of studies have reported temperature effects on two-phase relative permeabilities in porous media. Some of the reported results, however, have been contradictory. Also, observed effects have not been explained in terms of fundamental properties known to govern two-phase flow. The purpose of this study was to attempt to isolate the fundamental properties affecting two-phase relative permeabilities at elevated temperatures. Laboratory dynamic-displacement relative permeability measurements were made on unconsolidated and consolidated sand cores with water and a refined white mineral oil. Experiments were run on 2-in. [5.1-cm] -diameter, 20-in. [52.-cm] -long cores from room temperature to 300F [149C]. Unlike previous researchers, we observed essentially no changes with temperature in either residual saturations or relative permeability relationships. We concluded that previous results may have been affected by viscous previous results may have been affected by viscous instabilities, capillary end effects, and/or difficulties in maintaining material balances. Introduction Interest in measuring relative permeabilities at elevated temperatures began in the 1960's with petroleum industry interest in thermal oil recovery. Early thermal oil recovery field operations (well heaters, steam injection, in-situ combustion) indicated oil flow rate increases far in excess of what was predicted by viscosity reductions resulting from heating. This suggested that temperature affects relative permeabilities. One of the early studies of temperature effects on relative permeabilities was presented by Edmondson, who performed dynamic displacement measurements with crude performed dynamic displacement measurements with crude and white oils and distilled water in Berea sandstone cores. Edmondson reported that residual oil saturations (ROS's) (at the end of 10 PV's of water injected) decreased with increasing temperature. Relative permeability ratios decreased with temperature at high water saturations but increased with temperature at low water saturations. A series of elevated-temperature, dynamic-displacement relative permeability measurements on clean quartz and "natural" unconsolidated sands were reported by Poston et al. Like Edmondson, Poston et al. reported a decrease in the "practical" ROS (at less than 1 % oil cut) as temperature increased. Poston et al. also reported an increase in irreducible water saturation. Although irreducible water saturations decreased with decreasing temperature, they did not revert to the original room temperature values. It was assumed that the cores became increasingly water-wet with an increase in both temperature and time; measured changes of the IFT and the contact angle with temperature increase, however, were not sufficient to explain observed effects. Davidson measured dynamic-displacement relative permeability ratios on a coarse sand and gravel core with permeability ratios on a coarse sand and gravel core with white oil displaced by distilled water, nitrogen, and superheated steam at temperatures up to 540F [282C]. Starting from irreducible water saturation, relative permeability ratio curves were similar to Edmondson's. permeability ratio curves were similar to Edmondson's. Starting from 100% oil saturation, however, the curves changed significantly only at low water saturations. A troublesome aspect of Davidson's work was that he used a hydrocarbon solvent to clean the core between experiments. No mention was made of any consideration of wettability changes, which could explain large increases in irreducible water saturations observed in some runs. Sinnokrot et al. followed Poston et al.'s suggestion of increasing water-wetness and performed water/oil capillary pressure measurements on consolidated sandstone and limestone cores from room temperature up to 325F [163C]. Sinnokrot et al confirmed that, for sandstones, irreducible water saturation appeared to increase with temperature. Capillary pressures increased with temperature, and the hysteresis between drainage and imbibition curves reduced to essentially zero at 300F [149C]. With limestone cores, however, irreducible water saturations remained constant with increase in temperature, as did capillary pressure curves. Weinbrandt et al. performed dynamic displacement experiments on small (0.24 to 0.49 cu in. [4 to 8 cm3] PV) consolidated Boise sandstone cores to 175F [75C] PV) consolidated Boise sandstone cores to 175F [75C] with distilled water and white oil. Oil relative permeabilities shifted toward high water saturations with permeabilities shifted toward high water saturations with increasing temperature, while water relative permeabilities exhibited little change. Weinbrandt et al. confirmed the findings of previous studies that irreducible water saturation increases and ROS decreases with increasing temperature. SPEJ P. 945

2014 ◽  
Vol 1010-1012 ◽  
pp. 1676-1683 ◽  
Author(s):  
Bin Li ◽  
Wan Fen Pu ◽  
Ke Xing Li ◽  
Hu Jia ◽  
Ke Yu Wang ◽  
...  

To improve the understanding of the influence of effective permeability, reservoir temperature and oil-water viscosity on relative permeability and oil recovery factor, core displacement experiments had been performed under several experimental conditions. Core samples used in every test were natural cores that came from Halfaya oilfield while formation fluids were simulated oil and water prepared based on analyze data of actual oil and productive water. Results from the experiments indicated that the shape of relative permeability curves, irreducible water saturation, residual oil saturation, width of two-phase region and position of isotonic point were all affected by these factors. Besides, oil recovery and water cut were also related closely to permeability, temperature and viscosity ratio.


1970 ◽  
Vol 10 (02) ◽  
pp. 171-180 ◽  
Author(s):  
S.W. Poston ◽  
S. Ysrael ◽  
A.K.M.S. Hossain ◽  
E.F. Montgomery

Poston, S.W., Junior Member AIME, Nigerian Gulf Oil Co., Lagos, Nigeria Ysrael, S., Shell Oil Co., Los Angeles, Calif. Hossain, A.K.M.S., Junior Member AIME, Saudi Arabia Oil Ministry, Dhahran, Saudi Arabia Montgomery III, E.F., Junior Member AIME, Shell Oil Co., New Orleans, La. Ramey Jr., H.J., Member AIME, Stanford U., Stanford, Calif. Abstract The injection of hot fluids into an oil reservoir has become an important oil recovery process in the last few years. Numerous publications have considered the estimation of oil displacement under hot water or steam injection. None have considered the potential effects of temperature level upon relative permeabilities under immiscible displacement. In view of the work of Corey, Wyllie and Garaner, and Naar and Henderson, it appears reasonable to expect some sort of change in relative permeability with temperature change because the residual oil saturation depends upon temperature level. To investigate this possibility, isothermal water-oil displacements were carried out at various temperature levels with two unconsolidated sands. Both a natural oil sand and a clean quartz sand were used. Three oils were used having viscosities at room temperature of 80, 99 and 600 cp. Temperature level varied from 70 degrees F to approximately 300 degrees F. Initial saturations were established by displacing a core containing 100-percent deaerated water to a practical, irreducible water saturation with oil. Initially, this was done at room temperature for all runs. But it was observed that only oil was displaced from the core by thermal expansion upon heating to run temperature. Additional runs were made by establishing irreducible water saturation at the elevated run temperature. This indicated a significant increase in irreducible water saturation with temperature increase for some systems. A study of the effect of temperature level upon both oil-water contact angles and interfacial tension was made. The result indicated that, although interfacial forces decreased with temperature increase, oil-water-solid systems studied became more water-wet with temperature increase. After establishing saturations, the core was displaced with water isothermally at various temperature levels in succeeding runs. Results were used to compute oil and water relative permeabilities at various temperature levels. Results indicated important increases in both oil and water relative permeabilities as temperature increased. The Johnson-Bossler-Naumann dynamic relative permeability determination method was used. Although studies were carried out for a limited number of oils in unconsolidated sands, it appears that relative permeabilities may depend markedly upon temperature level. Introduction Recently, the injection of hot fluids into an oil reservoir has become an important oil recovery process. Due to the relative newness of the method and potential competitive advantage, few technical studies have been published. Most of the publications concerning hot fluid injection have dealt either with the results of field tests or with the gross heat transport involved with this type of fluid injection. The first detailed study of the injection of hot fluids into an oil reservoir was published in 1961 by Willman et al. They presented experimental results of cold water, hot water, and steam injection into consolidated sandstone cores to displace oil. The authors postulated the oil displacement mechanism involved in hot fluid injection and advanced a design method. The method involved the assumption that relative permeability was independent of temperature. SPEJ P. 171ˆ


Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Jin Yan ◽  
Rongchen Zheng ◽  
Peng Chen ◽  
Shuping Wang ◽  
Yunqing Shi

During the development of tight gas reservoir, the irreducible water saturation, rock permeability, and relative permeability change with formation pressure, which has a significant impact on well production. Based on capillary bundle model and fractal theory, the irreducible water saturation model, permeability model, and relative permeability model are constructed considering the influence of water film and stress sensitivity at the same time. The accuracy of this model is verified by results of nuclear magnetic experiment and comparison with previous models. The effects of some factors on irreducible water saturation, permeability, and relative permeability curves are discussed. The results show that the stress sensitivity will obviously reduce the formation permeability and increase the irreducible water saturation, and the existence of water film will reduce the permeability of gas phase. The increase of elastic modulus weakens the stress sensitivity of reservoir. The irreducible water saturation increases, and the relative permeability curve changes little with the increase of effective stress. When the minimum pore radius is constant, the ratio of maximum pore radius to minimum pore radius increases, the permeability increases, the irreducible water saturation decreases obviously, and the two-phase flow interval of relative permeability curve increases. When the displacement pressure increases, the irreducible water saturation decreases, and the interval of two-phase flow increases. These models can calculate the irreducible water saturation, permeability and relative permeability curves under any pressure in the development of tight gas reservoir. The findings of this study can help for better understanding of the productivity evaluation and performance prediction of tight sandstone gas reservoirs.


Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-14
Author(s):  
Cheng Lu ◽  
Xuwen Qin ◽  
Lu Yu ◽  
Lantao Geng ◽  
Wenjing Mao ◽  
...  

Many hydrate-bearing sediments in the Shenhu area of the South China Sea are featured with unconsolidated clayed silt, small particle size, and high content of clay, which can pose a great challenge for gas production. In order to investigate the gas-water relative permeability in clay-silt sediments, through a radial flow experiment, samples from the target sediment in the Shenhu area were selected and studied. The results show that the irreducible water saturation is high and the influence of the gas-water interaction is obvious. The relative permeability analysis shows that the two-phase flow zone is narrow and maximum gas relative permeability is below 0.1. The flow pattern in clay-silt sediment is more complicated, and the existing empirical models are inadequate for flow characterization. The depressurization method to extract a hydrate reservoir with clay-silt sediments faces the problem of insufficient production capacity. Compared with the ordinary hydrate reservoir with sandstone sediment, the hydrate reservoir with clay-silt sediment has a low permeability and poor gas flow capacity. The gas-water ratio abnormally decreases during the production. It is urgent to enhance production with cost-effective measures.


1964 ◽  
Vol 4 (01) ◽  
pp. 49-55 ◽  
Author(s):  
Pietro Raimondi ◽  
Michael A. Torcaso

Abstract The distribution of the oil phase in Berea sandstone resulting from increasing and decreasing the water saturation by imbibition was investigated Three types of distribution were recognized: trapped, normal and lagging. The amount of oil in each of these distributions was determined as a function of saturation by carrying out a miscible displacement in the oil phase under steady-state conditions of saturation. These conditions were maintained by flowing water and oil simultaneously in given ratios and by using a displacing solvent having essentially the same density and viscosity as the oil.A correlation shows the amount of trapped oil at any saturation to be directly proportional to the conventional residual oil saturation Sir The factor of proportionality is related to the fractional permeability to the water phase. Part of the oil which was not trapped was displaced in a piston- like manner (normal part) and part was eluted gradually (lagging part). The observed phenomena are more than of mere academic importance. Oil which is trapped may well provide the fuel essential for forward combustion and thus be beneficial. On the contrary, in tertiary recovery operations, it is this trapped oil which seems to make current techniques uneconomic. Introduction A typical oilfield may initially contain connate water and oil. After a period of primary production water often enters the field either from surrounding aquifers or from surface injection. During primary production evolution and establishment of a free gas saturation usually occurs. The effect and importance of this third phase is fully recognized. However, this investigation is limited to a two- phase system, one wetting phase (water) and one non-wetting phase (oil). The increase in water content of a water-wet system is termed imbibition. In a relative permeability-saturation diagram such as the one shown in Fig. 1, the initial conditions of the field would he represented by a point below a water saturation of about 35 per cent, i.e., where the imbibition and the drainage curves to the non-wetting phase nearly coincide. When water enters the field the relative permeability to oil decreases along the imbibition curve. At watered-out conditions the relative permeability to the oil becomes zero. At this point a considerable amount of oil, called residual oil, (about 35 per cent in Fig. 1) remains unrecovered. Any attempt to produce this oil will require that its saturation be increased. In Fig. 1 this would mean retracing the imbibition curve upwards. In addition, processes like alcohol and fire flooding, which can be employed at any stage of production, involve the complete displacement of connate water and an increase, or imbibition, of water saturation ahead of the displacing front. Thus, in several types of oil production it is the imbibition-relative permeability curve which rules the flow behavior. For this reason a knowledge of the distribution of the non-wetting phase, as obtained through imbibition, whether "coming down" or "going up" on the imbibition curve, is important. SPEJ P. 49^


2013 ◽  
Vol 2013 ◽  
pp. 1-5
Author(s):  
M. H. Alawi ◽  
M. M. El-Qadi ◽  
M. A. El-Ameen

Porous asphalt is a standard asphalt built on aggregate storage bed which allows water to drain through it and reduces stormwater runoff. However, porosity of the porous asphalt and the storage bed may be effectively reduced due to trapping suspended solids from the water or from the asphalt damage. In this paper, we present mathematical modeling and numerical simulation of flow and damage of porous asphalt-paved roads. A mathematical model to describe the fine-particles transport carried by a two-phase flow in a porous medium is presented. The buoyancy, capillarity, and mixed relative permeabilities correlations to fit with the mixed-wet system are considered. Throughout this investigation, we monitor the changing of the fluids properties such as water saturation and solid properties such as porosity and permeability due to trapping the fine-particles.


2019 ◽  
Vol 89 ◽  
pp. 01004
Author(s):  
Dylan Shaw ◽  
Peyman Mostaghimi ◽  
Furqan Hussain ◽  
Ryan T. Armstrong

Due to the poroelasticity of coal, both porosity and permeability change over the life of the field as pore pressure decreases and effective stress increases. The relative permeability also changes as the effective stress regime shifts from one state to another. This paper examines coal relative permeability trends for changes in effective stress. The unsteady-state technique was used to determine experimental relativepermeability curves, which were then corrected for capillary-end effect through history matching. A modified Brooks-Corey correlation was sufficient for generating relative permeability curves and was successfully used to history match the laboratory data. Analysis of the corrected curves indicate that as effective stress increases, gas relative permeability increases, irreducible water saturation increases and the relative permeability cross-point shifts to the right.


1990 ◽  
Vol 112 (4) ◽  
pp. 239-245 ◽  
Author(s):  
S. D. L. Lekia ◽  
R. D. Evans

This paper presents a new approach for the analyses of laboratory-derived capillary pressure data for tight gas sands. The method uses the fact that a log-log plot of capillary pressure against water saturation is a straight line to derive new expressions for both wetting and nonwetting phase relative permeabilities. The new relative permeability equations are explicit functions of water saturation and the slope of the log-log straight line of capillary pressure plotted against water saturation. Relative permeabilities determined with the new expressions have been successfully used in simulation studies of naturally fractured tight gas sands where those determined with Corey-type expressions which are functions of reduced water saturation have failed. A dependence trend is observed between capillary pressure and gas permeability data from some of the tight gas sands of the North American Continent. The trend suggests that the lower the gas permeability, the higher the capillary pressure values at the same wetting phase saturation—especially for saturations less than 60 percent.


1979 ◽  
Vol 19 (01) ◽  
pp. 15-28 ◽  
Author(s):  
P.M. Sigmund ◽  
F.G. McCaffery

Abstract With typical heterogeneous carbonate coresamples, large uncertainties of unknown magnitudecan occur in the relative permeabilities derived using different methods. This situation can beimproved by analyzing the recovery and pressureresponse to two-phase laboratory displacement tests by a nonlinear least-squares procedure. Thesuggested technique fits the finite-differencesolution of the Buckley-Leverett two-phase flowequations(which include capillary pressure) to theobserved recovery and pressure data. The procedureis used to determine relative-permeability curves characterized by two parameters and their standarderrors for heterogeneous cores from two Albertacarbonate reservoirs. Introduction Several recent investigations have recognizedpossible problems when obtaining reliable two-phasedisplacement data from heterogeneous carbonate core samples. Huppler stated that waterfloodresults on cores with significant heterogeneitiescan be sensitive to flooding rate, core length, andwettability, and that these effects should beconsidered before applying the laboratory results atfield flooding rates. Brandner and Slotboomsuggested that realistic displacement results maynot be obtainable when vertically flooding aheterogeneous core with a nonwetting phase becauseof the fluid's inability to maintain a properdistribution when the sample length is less than the height of capillary rise. Ehrlich noted thatstandard relative-permeability measurement methodsusing core plugs cannot be applied when the media are heterogeneous. Archer and Wong reported that application of theconventional Johnson- Bossler - Neumann (JBN)methods for determining relative permeabilities froma waterflood test could give erroneous results forheterogeneous carbonate as well as for relativelyhomogeneous porous media having a mixed wettability (see Refs. 1, 6, and 7). The observedstepwise or humped shape of water relativepermeability curves mainly were attributed to theeffect of water breakthrough ahead of the main floodfront entering into the JBN calculation. Archer andWong suggested that such abnormally shapedrelative-permeability curves do not represent theproperties of the bulk of the core sample, and proposed the use of a reservoir simulator forinterpreting laboratory waterflood data. The work referred to above provides the majorbackground for this study involving the developmentof an improved unsteady-state test method tocharacterize the relative-permeability properties ofheterogeneous carbonate core samples. The methodcan be applied to all porous media, regardless ofthe size and distribution of the heterogeneities.However, the presence of large-scaleheterogeneities, especially in the form of vugs, fractures, and stratification, could cause the derivedrelative-permeability relations to be affected by viscosityratio and displacement rate. Remember also that extrapolation of any core test data to a field scaleis associated with many uncertainties, particularlyfor heterogeneous formations. The inclusion ofcapillary pressure effects permits the interpretationof displacement tests at reservoir rates. The proposed calculation procedure extends theapproach suggested by Archer and Wong in thatthe degree of fit between observed laboratory dataand simulator results is quantified. We suggest thatrelative-permeability curves for a variety of rocktypes can be expressed in terms of two adjustable parameters and their standard error estimates.To illustrate the method, the results of displacementtests performed on cores from Swan Hills Beaverhill Lake limestone oil reservoir and Rainbow F KegRiver dolomite oil reservoir are interpreted. SPEJ P. 15^


2018 ◽  
Vol 41 (1) ◽  
pp. 1-15
Author(s):  
Prof. Dr. Ir. Bambang Widarsono, M.Sc.

Information about drainage effective two-phase i.e. quasi three-phase relative permeability characteristics of reservoir rocks is regarded as very important in hydrocarbon reservoir modeling. The data governs various processes in reservoir such as gas cap expansion, solution gas expansion, and immiscible gas drive in enhanced oil recovery (EOR). The processes are mechanisms in reservoir that in the end determines reserves and resevoir production performance. Nevertheless, the required information is often unavailable for various reasons. This study attempts to provide solution through customizing an existing drainage relative permeability model enabling it to work for Indonesian reservoir rocks. The standard and simple Corey et al. relative permeability model is used to model 32 water-wet sandstones taken from 5 oil wells. The sandstones represent three groups of conglomeratic sandstones, micaceous-argillaceous sandstones, and hard sandstones. Special correlations of permeability irreducible water saturation and permeability ratio irreducible water saturation have also been established. Model applications on the 32 sandstones have yielded specific pore size distribution index (?) and wetting phase saturation parameter (Sm) values for the three sandstone groups, and established a practical procedure for generating drainage quasi three-phase relative permeability curves in absence of laboratory direct measurement data. Other findings such as relations between ? and permeability and influence of sample size in the modeling are also made.


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