Properties Of Brine Research Articles

THERMAL AND RHEOLOGICAL PROPERTIES OF BRINE FROM FERMENTED AND SULFITE‐PRESERVED CUCUMBERS1

ABSTRACTPickling cucumbers may be temporarily preserved by fermentation in brine (6–8% NaCl) or without fermentation in salt‐free, sulfite solution (300 ppm sulfite, pH 3.5). Brines obtained from preservation processes are often discarded. Due to environmental concerns, there is increasing consideration for further use of the brine solutions by recycling for use in bulk storage or filtration and incorporation into finished products. Thermal and rheological properties are fundamental to the reuse of the brine. The effect of temperature was determined on the rheological (5–45C) and thermal properties (5–75C) of brine. The properties of the brine samples were found to be significantly different (P < 0.05) from each other and from water. Salt content was the most important factor affecting the thermal and rheological properties of brine. At the same conditions, the values of the properties (thermal conductivity, specific heat, and thermal diffusivity, viscosity) were about 5 to 23% less than the corresponding values for water.

ANALYSIS OF THE REFLECTION AND TRANSMISSION COEFFICIENTS IN THREE-PHASE SANDSTONE RESERVOIRS

As it is well-known, seismic and acoustic data play a very important role in the characterization of hydrocarbon reservoirs. The correct interpretation of the anomalies observed in seismic wave velocities, quality factors and reflection coefficients in such environments makes necessary to use accurate models taking into account the main petrophysical features of the rocks. This also brings into play the importance of adequately describing the in situ properties of the reservoir fluids. This work investigates the influence of gas saturation and excess pore fluid pressure on wave energy splitting at plane interfaces within a Biot-type porous medium saturated by a liquid–gas mixture. Using laboratory measurements made on a wide variety of sandstones, we incorporate in the model the effective pressure dependence of rock matrix properties such as bulk and shear modulus, porosity and pore space compressibility. Also, using empirical laws, we estimate the properties of real hydrocarbon gases, oils and brines of different compositions under variable pressure and temperature conditions. We present analytical computations of the amplitude reflection and transmission coefficients to study the combined effect of the forementioned variables, aiming at a further AVA trend analysis.

Analysis of the Reflection and Transmission Coefficients in Three-Phase Sandstone Reservoirs

As it is well-known, seismic and acoustic data play a very important role in the characterization of hydrocarbon reservoirs. The correct interpretation of the anomalies observed in seismic wave velocities, quality factors and reflection coefficients in such environments makes necessary to use accurate models taking into account the main petrophysical features of the rocks. This also brings into play the importance of adequately describing the in situ properties of the reservoir fluids. This work investigates the influence of gas saturation and excess pore fluid pressure on wave energy splitting at plane interfaces within a Biot-type porous medium saturated by a liquid–gas mixture. Using laboratory measurements made on a wide variety of sandstones, we incorporate in the model the effective pressure dependence of rock matrix properties such as bulk and shear modulus, porosity and pore space compressibility. Also, using empirical laws, we estimate the properties of real hydrocarbon gases, oils and brines of different compositions under variable pressure and temperature conditions. We present analytical computations of the amplitude reflection and transmission coefficients to study the combined effect of the forementioned variables, aiming at a further AVA trend analysis.

Comparison of Correlation Equations for Estimating Brine Properties under High Pressure and Temperature Condition

ABSTRACT Values of reservoir brine properties are often needed when laboratory PVT data are not available. Accurate knowledge of the physical properties of water under the influence of temperature and pressure is important for predicting behavior of reservoirs containing brine or geopressured-geothermal aquifers. This study involves an evaluation of literature information on physical properties of brine and comparison of the correlation results with experimental values. Brine properties compared include compressibility, formation volume factor, solution gas-water ratio, and viscosity. An observation drawn from the comparison study indicates that values of brine properties estimated using correlations agree well with the experimental data to within 10% for most cases. However, cautions should be given to correlations for viscosity because large variations among correlated and experimental values were observed.

Dynamic modeling of multistage flash desalination plants

A model for the dynamic simulation of multistage flash desalination units has been developed, based on a detailed description of the fundamental elementary phenomena involved in the process. It takes into account stage geometry, physico-chemical and transport properties of water, vapor and brine and the different non-idealities of the process. In this work the model is used to describe the behavior of the MSF plant under different kinds of process disturbances, thus showing some of its nonlinear dynamic features. Further applications of the model may deal with the analysis of steady-state stability and the development of optimal control strategies and start-up/shut-down procedures.

Field testing of an optical fiber temperature sensor in a geothermal

A program has been initiated for developing and field testing optical fiber sensors to monitor in situ physical and chemical parameters in highly corrosive environments, such as geothermal wells, oil wells, and hot-water boiler reactors. The difficulty of sampling hot geothermal fluids or reliably measuring physical and chemical properties of brines in wells limits our understanding of in situ conditions in geothermal fields. In this communication, the authors report a test of the concept of utilizing optical fiber based sensors by measuring the temperature profile of a geothermal steam well. The purpose of this work is not only to demonstrate that a temperature optical chemical sensor (optrode) can be used to obtain realtime information from a geothermal well, but also that great potential of the optrodes can be exploited for measuring physical and chemical parameters in the field. It is believed that this is the first real-time, in situ, geothermal well measurement to have been made using an optical fiber sensor.

Modeling geothermal brine process chemistry

Problems associated with the manipulation of highly concentrated brines at high temperatures have severely hindered the development of important geothermal energy resources in the Imperial Valley of Southern California and in other locations. One of the most serious of these problems is the precipitation of various mineral phases when the working fluid becomes supersaturated due to changes in external pressure or temperature. Scaling in well bores can significantly diminish flow rates and eventually seal the well. Precipitation of minerals in the energy production plant can cause costly downtimes in order to remove scales from the operating equipment. Similar chemical problems arise when spent geothermal brines are injected into an incompatible mineral formation. In this report we describe a chemical model which accurately predicts the properties of geothermal brines.

The dielectric properties of brine in sea ice at microwave frequencies

The dc conductivity and complex dielectric constant at frequencies of 7.50, 9, 11, 30, and 40 GHz of 16 samples of sea water brine in equilibrium with sea ice with freezing temperatures ranging from - 2.8\deg C to -25.0\deg C have been measured. The data is analyzed to yield parameters occurring in a Debye relaxation equation so that the dielectric constant of brine may be calculated throughout the microwave region of the electromagnetic spectrum.

Guidelines for Using HEC Polymers for Viscosifying Solids-Free Completion and Workover Brines

Summary Solids-free brines are used increasingly in well completion and workover operations. One technique to minimize downhole losses of expensive, high-density brine is to spot a pill of viscosified brine across the thief zone. Hydroxyethylcellulose (HEC) is the polymer used most frequently for this purpose. This report discusses the properties of HEC-thickened brines and presents guidelines for their use for completion and workover fluid-loss control. Introduction When using solids-free brines, well control is achieved by using a slight overbalance. With calcium chloride and lower-density brines, the fluid loss resulting from this overbalance often is ignored because the brine costs are relatively low. For example, saturated CaCl2 brine [11.6 lbm/gal) costs about $15/bbl. However, costs rise sharply with increasing brine density. For example, a 19-lbm/gal CaBr2/ZnBr2 brine currently costs about $820/bbl. There are two basic methods for minimizing fluid loss--adding solids or increasing brine viscosity. The traditional approach has been to add filter-cake-forming particles, preferably of an acid-soluble material such as particles, preferably of an acid-soluble material such as calcium or iron carbonate. There is increasing concern regarding our ability to remove these filter cakes adequately. The problem is that the zone where the acid first breaks through may be the only section that gets cleaned. Other sections of the wellbore then may not be exposed to sufficient acid and/or contact time for good cleanup. This problem is expected to be more severe when using iron carbonate (siderite, FeCO3), since its dissolution rate in acid is at least 30 times slower than that of calcium carbonate. More recently, the method of using solids-free viscosity pills is receiving increased attention. With this method, a clean brine pill is viscosified with a soluble polymer and spotted across the thief zone to develop a polymer and spotted across the thief zone to develop a bank of high-viscosity fluid in the formation, which will retard further fluid losses. As might be expected, there are a variety of factors related to both the polymer and brine that influence the effectiveness of viscosity pills in controlling fluid loss. This paper discusses some of these factors and presents data and guidelines that will be useful when employing viscosity pills to control fluid loss. Discussion The chemistry and rheology of polymer solutions are complex. Hence, within the limited scope of this study, we were able only to define trends and general-use guidelines.Polymer solution apparent viscosity is very shearsensitive.Increasing shear rate decreases viscosity and increases fluid loss.Increasing brine and HEC concentration increases viscosity and decreases fluid loss.Increasing temperature decreases viscosity and increases fluid loss.Increasing brine density above about 12 lbm/gal decreases the hydration rate of HEC polymer sufficiently so that heat and/or extended mixing times are required to develop full solution viscosity. Further discussion of these effects follows. JPT P. 306

Laboratory Core Floods To Support the El Dorado Micellar/Polymer Project

Summary Two distinct micellar/polymer processes are being testedin the El Dorado project. In one pilot area, anoil-external micellar system followed by partiallyhydrolyzed polyacrylamide solution is being tested. In the north pattern, an aqueous surfactant system followed byxanthan gum solution is being implemented. Throughoutthe project, laboratory work has been required toevaluate various substitute chemicals when suchsubstitutions were deemed necessary and feasible.Several short core flow tests were conducted using Bereasandstone cores and Admire sandstone (field) cores toinvestigate the effects of various changes on theeffectiveness of the two processes. Among the factorsinvestigated and/or observations were (1) effects of chemical slug size on oil recovery for both oil- andwater-external systems,(2) effects of surfactant andpolymer concentrations on the effectiveness of thehigh-water content system, (3) efficiencies of the systemswhen different commercial polymers were used in thepolymer drives, (4) effects of polymer drive salinity onoil recovery using the aqueous system, and(5) effects ofvarious substitute low-equivalent-weight (LEW) sulfonates on the displacement efficiency of the aqueous surfactantsystem. Introduction The literature contains many performance data formicellar or surfactant systems with quite diversecompositions. Compositions of slugs used in micellar orsurfactant flooding generally include a combination ofsurfactant, water, salt, cosolvent, hydrocarbon, andpolymer. Considerable effort has been spent defining ordetermining the optimal combination of these ingredients for a given set of rock, oil, and brine properties. Inaddition to these compositional variables, other parametersto consider in the surfactant flooding process are mobilitiesof the surfactant slug and the polymer solution, surfactantslug size, type and concentration of polymer for thepolymer drive, composition, size, and pH of a preflush, salinities of all three phases (preflush, surfactant, andpolymer) of the process, and rock properties such aslithology, mineralogy, pore size distribution, andwettability. Considering the number of variables it is notsurprising that there are differing opinions on the optimalsurfactant concentration and surfactant slug size forrecovery of additional oil from waterflooded laboratory cores and field reservoirs. One difficulty in defining theoptimum in such a multidimensional space (manyvariables) is that it is nearly impossible to vary only oneparameter and hold all others constant. For example, changing the surfactant concentration simultaneouslymay cause a change in the slug viscosity, giving rise to acorresponding change in the mobility ratio between theoil/water bank and the surfactant slug. Gogarty compared results for three compositionsdiffering in the active surfactant concentration in thesurfactant slug. Other laboratory work reports the importantor the unimportant nature of the surfactant slug withregard to its external phase and/or surfactantconcentration. Holm found that an oil-external, high-concentration type surfactant slug performs better under the given conditions. For the given surfactant system andtest conditions, Klaus found that lower concentrationslugs (0.5%) yielded a higher oil recovery per gram ofsulfonate injected. Other work on the nature of theexternal phase of micellar systems indicates that therelative amounts of oil and water that a microemulsioncan solubilize are controlled at least partially bycosolvent type and concentration and not by phase externality.Accordingly, an oil-external system was concluded notto be preferred intrinsically over a water-externalsystem. JPT P. 1378^

Calculating the thermal conductivity of meat and fish in the freezing range

In the absence of exact data for the physical properties of the brine contents of meat and fish, the author proposes an ‘Ersatz’ brine model bases on the known properties of commercial brines. The resulting thermal conductivities of the slush and that of the dry muscle are introduced into the modified Maxwell-Eucken equation for calculating the conductivity in the freezing range for several meats and fish of varying brine contents. A series of 15 test diagrams taken from various publications is analysed and discussed.

Brine substitute liquids for soil freezing at very low temperatures

The strength of a frozen soil increases with decreasing temperature. Furthermore, the speed it takes to form a frozen wall increases on lowering the temperature of the freezing liquid.With the traditional freezing systems using brine it is difficult to work with temperatures below −30°C. To go lower than this limit, it is necessary to substitute the brine by using freezing liquids that maintain good hydraulic and thermal characteristics at much lower temperatures.Different organic liquids have been tested and good results have been obtained with some aromatic hydrocarbon mixes from the terpene family.As a result of the research, for practical purposes a by-product ofa distilling citrus fruit skins has been selected. This liquid solidifies at −100°C approx. and maintains a low viscosity rate below −30°C.The present paper describes the thermal and hydraulic properties of this product as a function of the temperature concerned and compares them to the same properties of classic brines of CaCl2.

Selective Extraction of Tungsten from Searles Lake Brines

Abstract Tungsten was successfully extracted from the brines of Searles Lake, Calif., in a demonstration unit based on 9 years of laboratory research conducted by the U.S. Department of the Interior, Bureau of Mines. Pilot-scale operation was initiated in July 1979 at the Westend facility of the Kerr-McGee Chemical Corp. at Trona, Calif. The extractive method, based on a novel ion exchange resin, resulted from research supporting one of the Bureau's goals: helping to insure an adequate supply of minerals to meet national economic and strategic needs. The objectives met during pilot testing included proving operational viability during seasonal changes in brine properties, concentrating the tungsten to enable concluding tungsten recovery research, supplying escalation data necessary for commercialization, and confirming earlier small-scale laboratory work. The demonstration unit typically removed 92 percent of the tungsten from alkaline brine using QRF (8-hydroxyquino-line-resorcinol-formaldehyde) resin beads produced by the Bureau. A “merry-go-round” system was employed whereby two 12-inch-diameter resin beds were loaded in series while a third bed was eluted. Testing was concluded after treating over 500,000 gallons of brine. Tungsten, isolated in the primary ion exchange system, was recon-centrated in a secondary ion exchange system. Several tungsten products were produced from tungsten-rich solutions.

Electrical Resistivity of Geothermal Brines

Introduction The electrical resistivity of dilute aqueous salt solutions has been studied for a number of years, but very few data exist on concentrations above 0.1 molar. Normal groundwaters commonly are near 0.1 molar, while most geothermal and oilfield fluids are at least several molar (Table 1). Thus, the interpretation of electrical measurements in geothermal areas at present is based mainly on extrapolation of lower temperature and lower concentration data. Such extrapolation may introduce serious errors into the interpretation of geothermal reservoir characteristics determined from electrical measurements. This paper presents new experimental data and an improved descriptive model of the electrical properties of brines as a function of temperature properties of brines as a function of temperature from 22 to 375 deg. C and concentration from roughly 3 to 26 wt% while under 31 MPa hydrostatic pressure. Data and models are given for brines composed of the chlorides of sodium, calcium, and potassium, and their mixtures. Comparison of the older log interpretation formulas to the new models illustrates an order of magnitude improvement in accuracy with an overall fit to within 2%. Resistivity Dependence Upon Temperature Some researchers have postulated that the electrical resistivity of fluid saturated rocks follows the temperature dependence of the saturating fluid in the absence of conducting minerals or significant surface conduction along altered pore walls. This assumption resulted from the success of a simple empirical formula relating the resistivity of a rock to the resistivity of the fluid filling the pores of the rock: Pr=FPw, where Pr= resistivity of clay-free, nonshale material that is 100% saturated, Pw= resistivity of saturating solution, and F= formation resistivity factor. A number of investigators have derived formulas that add the temperature of the saturating fluids. Experimental observations have shown that some rocks obey these formulas while others do not. 17–19 Part of the problem is the inadequate knowledge of Part of the problem is the inadequate knowledge of the resistivity dependence on temperature for the solution that fills the rock pores. We have found empirically that the best fit of the resistivity data to temperature is pw=bo+b1T-1 +b2T+b3T2+b4T3, where T is temperature and coefficients b are found empirically.

Measurement and Calculation of the Viscosity of Mixed Aqueous Solutions of NaCl and KCl in the Temperature Range 25150°C and the Pressure Range 0–30 MPa

AbstractIn order to facilitate the development of predictive methods for the calculations of the viscosity of brines containing several salts, we present measurements of the viscosity of mixtures of aqueous solutions, each containing a single salt, namely KCl and NaCl in this case. The mixtures studied included one of a total nominal molality of 2 mol/kg, and three of a total nominal molality of 4 mol/kg. ‐ The measurements cover a pressure range of 030 MPa and a temperature range of 25150°C and their uncertainty is somewhat better than ± 1%. ‐ The measurements are compared with calculations based on Young's rule, which was successfully used in the past for volumetric properties of mixed brines. The comparison is positive and indicates that a start has been made towards the formulation of a predictive method of calculation.

Saline‐Water Conversion: Committee Progress Report

This article provides a discussion of the specific activities of various programs and divisions within the Office of Saline Water (OSW) and presents a broad picture of the problems that lie ahead and the steps being taken to solve these problems. The long‐range program of OSW includes the support of fundamental research to provide information that may lead to new and improved desalting processes. This program is designed to insure scientific application of the present technology and the pursuit of other alternatives that may prove to be better in the future. Research studies were divided into four categories: properties of water; separation processes; interactions at boundaries; and, properties of brackish waters, salts, and brines.

Waterflood Mobility Control: A Case History

Abstract Performance of a pilot flood in eastern Kansas indicates improved recovery and accelerated production resulting from mobility ratio control obtained by adding a high molecular weight polymer to injected water. Ultimate pilot flood recovery of the 75-cp reservoir oil is anticipated to be 350 bbl/acre-ft during the six-year flood life. Cumulative recovery to date totals 242 bbl/acre-ft after 30 months of injection. Reservoir parameters and flood performance are discussed in detail to provide a case history relating to the feasibility of polymer flooding. Introduction The Vernon Polymer flood of the Brazos Oil and Gas Co., located in Sec. 2, 24 S., 16 E., Woodson County, Kans., was begun in late Oct., 1963. Injection of a 500 ppm solution of Pusher* polymer was initiated in a 15-acre pilot to determine feasibility of improving oil recovery by mobility ratio control. Performance to date and the anticipated recovery of 115,000 bbl from the 329 acre-ft pilot indicate efficient displacement of the viscous reservoir oil. Dependence of flood recovery on the displacing fluid-displaced oil mobility ratio has long been recognized. Displacement efficiency of the reservoir oil decreases with increasing mobility ratio. Therefore, economic reduction of this parameter is an attractive approach to improving oil recovery, particularly from viscous oil reservoirs where mobility ratios are often quite high. Waterflood mobility ratios can be controlled by dilute solutions of certain polymers which provide a displacing fluid with considerably reduced mobility. Reservoir parameters and flood performance are emphasized in this paper to provide data relating to polymer flood applicability. THEORY The polymer used in the Vernon pilot exhibits the property of unusually high resistance to flow through porous media. A small concentration in injected water effects a mobility reduction considerably beyond that predicted from increases in bulk viscosity as measured in a capillary or rotating cup viscosimeter. Water mobility in the subject flood is reduced by a factor of 7.55 with the addition of 500 ppm Pusher chemical to injected water while the bulk viscosity is increased from 1.03 to only 1.40 cp at 75F. The exact tow mechanism causing resistance to flow has not been established; however, it is observed only in tortuous flow systems and appears to be influenced by brine properties, rock properties and oil saturation. Consequently, mobility reduction is estimated from flow studies for a given sample of reservoir rock and is expressed in terms of a "resistance factor". This parameter is defined as the ratio of brine mobility to polymer solution mobility measured at residual oil saturation: .........(1) where RF = resistance factor (dimensionless)w and p = mobility of water and polymer solution, respectively kw and kp = water and polymer permeability, respectively (darcies)w and p = viscosity of water and polymer, respectively (poise). Eq. 1 is similar to the expression commonly used to relate the relative mobility of the water bank at residual oil saturation to oil-bank mobility at irreducible water saturation: ........(2) where Mw-o = mobility ratio of water to oil (dimensionless) o = mobility of oil ko = permeability to oil (darcies) o = oil viscosity (poise). From Eqs. 1 and 2 it is apparent that the polymer-solution-to-oil mobility ratio can be approximated by dividing the brine-to-oil ratio by the resistance factor RF: ..........(3) where Mp-o = mobility ratio of polymer solution to oil (dimensionless). This simplified presentation assumes no dilution of the polymer solution by connate water. Also, the presence of a connate water bank separating the polymer solution from the displaced oil is not considered. Displacement of oil by waterflooding is increasingly dominated by viscous forces as the viscosity of the oil displaced increases. When the oil mobility is less than that of the injected water, the oil-water interface is not a piston-like front. Instead, instabilities occur at the flood front in the form of viscous fingers which tend to penetrate the less mobile oil bank. JPT P. 1151ˆ

A Study of Formation Plugging With Bacteria

Abstract This study investigated the nature of formation plugging with bacteria and attempted to relate its characteristics to physical rock properties. Fifteen core samples of four specific formation types were defined and plugged using a commonly occurring, uniform sized dead bacteria, Bacillus subtilis. Two of the formation types were fairly uniform-grained sandstones and two were heterogeneous carbonates. The injection rate and concentration of solids in the brine were held constant during the test runs. The pore geometry factor G was a significant petro-physical rock characteristic for correlation with depth of plugging, but lacked importance as a parameter for rate of plugging. Although the G factor may not completely describe porous rock geometry for plugging predictions, for reservoirs with multi-pore systems, there is evidence that the pore geometry factor might form a basis for establishing injection water specification in more homogeneous reservoirs with only primary porosity development. Introduction GENERAL PURPOSE Injecting water into oil-bearing formations to increase recovery is common practice in the petroleum industry. One of the most serious operational problems involved with water injection wells is the tendency of the porous rock immediately adjacent to the injection wellbore to plug partially. This results in increased injection pressures and/or a decrease in the rate of injection. This plugging in injection wells can result from a number of causes, including bacteria contained in the injected water. The purpose of this work was to investigate the nature of injection plugging with bacteria and to attempt to relate its characteristics to physical rock properties. Many variables exist in research of this type, so, to reduce them, injection rate and concentration of bacteria in brine were held constant. The bacteria used for plugging was a uniform-sized, dead bacteria, Bacillus subtilis, a micro-organism commonly found in water, air and soils. Four specific porous rock types were plugged-two consolidated sandstones and two heterogeneous carbonates. The experimental work involved two distinct phases. The first concerned determining the physical rock properties and the second was the experimental work of actually plugging the selected core samples. PORE GEOMETRY FACTOR Capillary pressure is necessary to displace a wetting fluid from a capillary opening with a nonwetting fluid. The factors which govern capillary pressure are the surface or interfacial tension of the fluids involved, the system wettability and the equivalent pore radius. Thus: (1) Thomeer used the idea that the location and shape of the capillary pressure curve reflect characteristics of the pore structure of any porous media sample. He presented the mathematical description of capillary pressure curves and of indicated differences in pore geometry of samples. (2) where G = pore geometry factorpc = capillary pressurepd = displacement pressure(Vb)pc = fractional bulk volume occupied by thedisplacing fluid at any capillary pressure(Vb)px = fractional bulk volume occupied by thedisplacing fluid at infinite pressure ortotal inter-connected pore volumes. The shape of the curve is defined by the pore geometry factor G. The curve shape is related directly to the sorting and interconnection of the pores of the sample. The location of an infinite number of curves can be defined by the same asymptotes. However, these curves differ in shape, each curve being described by a specific value of G. Thus, the description of a curve is unique when, in addition to the position of its asymptotes, its shape is defined. These curves can be used graphically to determine the characteristic parameters of any arbitrarily located curve. Those parameters that can be approximated from any capillary pressure curve are: total interconnected pore volume, represented by (Vb)px; extrapolated displacement pressure, the abscissa axis; and pore geometry factor, by the curve shape. PROPERTIES OF BRINE AND BACTERIA The fluid used throughout this study was an aqueous solution of sodium chloride, 25,000 ppm by weight. The addition of salt to fresh water was intended to eliminate clay swelling in the sandstone cores and to retard leaching in the limestone cores. JPT P. 201ˆ

314. Ion movements in an omegatron: G. Schuchhard, Vacuum, 10, 373–376, 1960

The temperature dependence of electrical properties of single-component brines was extensively studied up to supercritical condi- tions. However, only very few data are available for multicomponent brines, representing natural geothermal fluid compositions. We present a new measuring cell, designed to investigate electrical resistivities of mixed salt solutions at conditions simulating su-percritical hydrothermal reservoirs. The cell was tested at 23 MPa and 23 – 380 °C on a diluted aqueous solution of NaCl, CaCl2, and K2SO4, simulating the Icelandic Krafla hydrothermal system. The measured data are used to calibrate resistivity measurementson fluid saturated rock samples, which are presented in an associated paper.