Brine Mixtures Research Articles

Improving Compatibility of Drilling Fluid, Completion Fluid, and Other Well-Treatment Fluids for Deepwater Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 141513, ’Chemical Additives for Improving Compatibility of Drilling Fluid, Completion Fluid, and Other Well-Treatment Fluids for Deepwater Wells,’ by Xiaoping (Victoria) Qiu, SPE, Lee Morgenthaler, SPE, Eddy Martch, SPE, Hiep Vu, SPE, Mootasem Chtay, and Vanessa Farrell David, Shell International E&P, prepared for the 2011 SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, 11-13 April. The paper has not been peer reviewed. In Gulf of Mexico (GOM) deepwater completions, synthetic-based mud (SBM) has been used widely for drilling the reservoir section. With increasing well depth and higher reservoir pressure, higher-density drilling fluids are used. It has been observed that with the increased density of drilling fluid, the incompatibility of drilling fluid, completion fluid, and other well-treatment fluids can cause additional problems in drilling and completion activities. Often, the formation damage caused by such incompatibility can be very difficult to remediate. Chemical additives were studied for preventing this incompatibility between drilling fluid, completion fluid, and other well-treatment fluids. Introduction In deep water, wellbore cleanup is critical for drilling and completing wells. There have been cases in the GOM in which several extra days were needed to achieve acceptable cleanup. Also, when displacement is not effective, mud residue may cause formation damage in the subsequent well completion. One displacement problem is that when completion brine or spacer fluid is mixed with SBM, the mixture may form very viscous, paste-like materials that are difficult to displace or can cause problems with shaker operations. In addition to mud displacement, the compatibility of SBM and injected fluids during frac-pack operations is important. Sometimes, loss of whole mud into the formation is unavoidable when drilling and completing a well at overbalanced conditions. The mixture of SBM and completion brine lost into the reservoir may become viscous and difficult to break and flow back. Injected frac-pack fluid or gravel-pack fluid also might contact the mud and form mixtures that are difficult to move and can reduce well productivity. In GOM well-completion operations, acids are sometimes pumped before the frac pack or gravel pack to clean up the post-perforation pill and to help clean up the perforations to improve fluid injectivity. Incompatibility of SBM and acids can affect well productivity significantly. Also, HCl, organic acids, and mud acids (such as HCl/HF or organic-acid/HF acid blends) may be pumped to clean up perforations or near-wellbore damage before the frac-pack fluid is injected. If mud remains in the wellbore or if SBM is lost to the reservoir, acid may come into contact with the SBM, resulting in the viscous paste-like mixture that is worse than the mixture of SBM and brine or SBM and spacer fluid.

Caprock interaction with CO2: A laboratory study of reactivity of shale with supercritical CO2 and brine

Abstract Crushed rock from two caprock samples, a carbonate-rich shale and a clay-rich shale, were reacted with a mixture of brine and supercritical CO 2 (CO 2 –brine) in a laboratory batch reactor, at different temperature and pressure conditions. The samples were cored from a proposed underground CO 2 storage site near the town of Longyearbyen in Svalbard. The reacting fluid was a mixture of 1 M NaCl solution and CO 2 (110 bar) and the water/rock ratio was 20:1. Carbon dioxide was injected into the reactors after the solution had been bubbled with N 2 , in order to mimic O 2 -depleted natural storage conditions. A control reaction was also run on the clay-rich shale sample, where the crushed rock was reacted with brine (CO 2 -free brine) at the same experimental conditions. A total of 8 batch reaction experiments were run at temperatures ranging from 80 to 250 °C and total pressures of 110 bar (∼40 bar for the control experiment). The experiments lasted 1–5 weeks. Fluid analysis showed that the aqueous concentration of major elements (i.e. Ca, Mg, Fe, K, Al) and SiO 2 increased in all experiments. Release rates of Fe and SiO 2 were more pronounced in solutions reacted with CO 2 –brine as compared to those reacted with CO 2 -free brine. For samples reacted with the CO 2 –brine, lower temperature reactions (80 °C) released much more Fe and SiO 2 than higher temperature reactions (150–250 °C). Analysis by SEM and XRD of reacted solids also revealed changes in mineralogical compositions. The carbonate-rich shale was more reactive at 250 °C, as revealed by the dissolution of plagioclase and clay minerals (illite and chlorite), dissolution and re-precipitation of carbonates, and the formation of smectite. Carbon dioxide was also permanently sequestered as calcite in the same sample. The clay-rich shale reacted with CO 2 –brine did not show major mineralogical alteration. However, a significant amount of analcime was formed in the clay-rich shale reacted with CO 2 -free brine; while no trace of analcime was observed in either of the samples reacted with CO 2 –brine.

Wettability Alteration of Clay in Solid-Stabilized Emulsions

Processing of bitumen froth obtained from surface mining process of Athabasca oil sands yields stable water-in-diluted bitumen emulsions. Even with a demulsifier, a “rag layer” forms between the oil and free water layers when clay solids are present. Experiments reveal that wettability of clay solids has a significant effect on emulsion stability. Kaolinite in toluene–brine mixture was chosen as model system to study clay wettability alteration related to emulsion separation in bitumen froth treatment. Sodium naphthenate was added to simulate the presence of naphthenic acid in diluted bitumen. The fraction of the kaolinite that settled to the bottom of the aqueous phase was measured, and was referred to as “water-wet fraction”, to characterize the wettability of kaolinite. Without any additives, 96% of the kaolinite was water-wet. Addition of only 100 ppm sodium naphthenate reduced the water-wet fraction to only 18%. Wettability of kaolinite was altered by pH control, silicate, and surfactant under different mechanisms. Addition of 366 ppm silicate at pH 10 resulted in 80% of kaolinite being water-wet. To prevent emulsion formation at high pH, cationic and amphoteric surfactants were evaluated as an alternative to alkali. Over 90% of kaolinite became water-wet when adding alkyl quaternary ammonium bromide, betaine, or amine oxide with optimal dosages.

Geochemistry and modification of oilfield brines in surface pits in Northern Kuwait

Oilfield brines (produced water) are produced as a waste product daily at the gathering centers (GCs) in Kuwait oilfields. The geochemical evolution of the water produced at the GC (fresh brine) to stagnant pit water (evaporate) has been investigated in the northern fields of Kuwait, and a model is presented showing time-dependent variations. Kuwait oilfield brines are globally similar to others in other large sedimentary basins (USA, Canada), but modifications have occurred due to seawater injection practices performed episodically during the oil extraction process. Brine water chemistry changes from generally average brine chemistry (based on cations and anions) to saturated mixture of seawater, oilfield brine, and anthropogenic chemical pollutants. The objective of this study was to harmonize the database of brine waters in terms of regional identity by comparison with oilfield brines elsewhere, identify water–rock interaction, and statistically treat daily recordings from the pits in order to identify injection peaks and troughs. Laboratory analysis of major and minor cations and anions from the Rawdatayn samples gave the following concentration ranges in parts per million (ppm): (Na+, 11,698–203,977), (Ca2+, 2,216–98,514), (Mg2+, 1,602–28,885), (K+, 1,528–16,573), (Sr2+, 70–502), (Ba2+, 0.01–18.04), (Fe2+, 0.01–8.93), (Li+, 0.09–6.48), (Si2+, 0.00–13.18), (B3+, 0.05–37.45), (SO42+, 330–3100). For the Sabriyah oilfield samples, the major and minor cations and anions concentration ranges in ppm are: (Na+, 9,807–274,947), (Ca2+, 2,555–77,992), (Mg2+, 1,415–28,183), (K+, 764–19,201), (Sr2+, 77.84–641), (Ba2+, 0.15–6.76), (Fe2+, 0.016–38.88), (Li+, 0.05–6.83), (Si2+, 0.0195–16.84), (B3+, 7.17–55.33), (SO42+, 44,812–135,264). The stable isotopic analysis of five samples indicates normal trends in oxygen and hydrogen isotopes that classify the waters as “connate” which follow an evaporation trend. Carbon isotopic signatures are normal for hydrocarbon fields and average out around GC15, δ18O‰ = 1.4, δD‰ = −10, δ13C‰ = −3.6; while for GC23, δ18O‰ = 2.3, δD‰ = −4, δ13C‰ = −2.5; for GC25, δ18O‰ = −2.0, δD‰ = −14, δ13C‰ = −4.6; for pit1, δ18O‰ = 2.3, δD‰ = −5, δ13C‰ = −18.3; and for pit 2, δ18O‰ = 2.5, δD‰ = −4, δ13C‰ = −17.8. Carbon isotope average values for all brine samples from the GCs is = −56 which falls within normal hydrocarbon formation water category. Data spikes coincide with injection periods at the following times (A: May–Jun, 2006), (B: Sep–Oct, 2006), (C: Jan–Feb, 2007), (D: Mar, 2007), (E: May–Jun, 2007), (F: Feb, 2006), (G: Mar–Apr, 2006) and, subsequently the decay to “normal” brine occurs over a period of several weeks. The database was large enough to apply a principal component statistical analysis (PCA). PCA and geo-statistical techniques reveal several distinct population groups. The main chemical groups in the data are as follows: plateau, spike groups, and pit evaporation group. The spike periods correlate closely with seawater injection periods (Jan–Feb, Mar–Apr, May–Jun, and Sep–Oct). The pit chemistry reveals exceptionally high evaporation processes coinciding with summer peak temperature. PCA results show distinct groupings centered around the major elements reminiscent of other oilfields, but with the added evaporation trend strongly enhanced.

Cross-borehole resistivity tomography of Arctic and Antarctic sea ice

AbstractAs an inhomogeneous mixture of pure ice, brine, air and solid salts the physical properties of sea ice depend on its highly temperature-dependent microstructure. Understanding the microstructure and the way it responds to variations in temperature and salinity is crucial in developing an improved understanding of the interaction between sea ice and the environment. However, measurements monitoring the internal structure of sea ice are difficult to obtain without disturbing its natural state. We have recently developed an application of cross-borehole d.c. resistivity tomography to make in situ measurements that resolve the anisotropic resistivity structure of first-year sea ice. We present results from measurements made in 2008 off Barrow, Alaska, and in 2009 off Ross Island, Antarctica. the sea ice in these two regions forms in different environments: at Barrow, relatively quiescent conditions typically lead to a predominance of columnar ice, while more turbulent conditions and underwater ice formation in McMurdo Sound tend to produce a larger component of frazil or platelet ice. Interpretation of the resistivity measurements carried out in association with temperature and salinity data collected simultaneously allows both observation of the temporal evolution of the ice structure and, in the case of the Antarctic measurements, the identification of different ice types.

Separation of Produced Emulsions from Surfactant Enhanced Oil Recovery Processes

Selected cationic and amphoteric surfactants were effective in separating oil-in-water emulsions representative of produced emulsions expected during a surfactant/polymer (SP) process for enhanced oil recovery. The aqueous phase of the emulsion contained an anionic surfactant blend, alcohol, and partially hydrolyzed polyacrylamide. Brine composition was a suitable mixture of formation brine with brines from the surfactant slug and polymer drive. The crude oil had an American Petroleum Institute (API) gravity of 31°. Bottle tests were conducted at ambient temperature, which is near the reservoir temperature. Conventional non-ionic demulsifier resins and polymeric cationic flocculants were not effective in removing oil from the aqueous phase. The water content of the oil phase was still well above specification upon heating the emulsions to 50−60 °C. However, both oil and water phases of acceptable quality were obtained after 6 h of settling upon the addition of 200 ppm of octyltrimethylammonium bromide (C8...

Experimental investigation of wellbore integrity and CO 2–brine flow along the casing–cement microannulus

Wellbore integrity is one of the key performance criteria in the geological storage of CO 2. It is significant in any proposed storage site but may be critical to the suitability of depleted oil and gas reservoirs that may have 10’s to 1000’s of abandoned wells. Much previous work has focused on Portland cement which is the primary material used to seal wellbore systems. This work has emphasized the potential dissolution of Portland cement. However, an increasing number of field studies (e.g., Carey et al., 2007), experimental studies (e.g., Kutchko et al., 2006) and theoretical considerations indicate that the most significant leakage mechanism is likely to be flow of CO 2 along the casing–cement microannulus, cement–cement fractures, or the cement–caprock interface. In this study, we investigate the casing–cement microannulus through core-flood experiments. The experiments were conducted on a synthetic wellbore system consisting of a 5-cm diameter sample of cement that was cured with an embedded rectangular length of steel casing that had grooves to accommodate fluid flow. The experiments were conducted at 40 ° C and 14 MPa pore pressure for 394 h. During the experiment, 6.2 l of a 50:50 mixture of supercritical CO 2 and 30,000 ppm NaCl-rich brine flowed through 10-cm of limestone before flowing through the 6-cm length cement–casing wellbore system. Approximately 59,000 pore volumes of fluid moved through the casing–cement grooves. Scanning electron microscopy revealed that the CO 2–brine mixture impacted both the casing and the cement. The Portland cement was carbonated to depths of 50–250 μ m by a diffusion-dominated process. There was very little evidence for mass loss or erosion of the Portland cement. By contrast, the steel casing reacted to form abundant precipitates of mixed calcium and iron carbonate that lined the channels and in one case almost completely filled a channel. The depth of steel corroded was estimated at 25– 30 μ m and was similar in value to results obtained with a simplified corrosion model. The experimental results were applied to field observations of carbonated wellbore cement by Carey et al. (2007) and Crow et al. (2009) to show that carbonation of the field samples was not accompanied by significant CO 2–brine flow at the casing–cement interface. The sensitivity of standard-grade steel casing to corrosion suggests that relatively straight-forward wireline logging of external casing corrosion could be used as a useful indicator of flow behind casing. These experiments also reinforce other studies that indicate rates of Portland cement deterioration are slow, even in the high-flux CO 2–brine experiments reported here.

Sequestration of CO2 in Mixtures of Caustic Byproduct and Saline Waste Water

Ex-situ carbonation of mixtures of caustic byproduct materials and produced oil-field brine provides a niche opportunity to sequester anthropogenic CO2, while concomitantly reducing the basicity of the reactive slurry. A series of tests were conducted to investigate a novel reaction concept designed to achieve neutralization of mixtures of acidic oil field produced brine and caustic industrial byproducts while sequestering substantial quantities of anthropogenic carbon dioxide (CO2) in a mixed-flow reactor. Experiments were conducted to determine the CO2-bearing capacity of reactive mixtures of brine from the Oriskany Sandstone Formation with three caustic industrial byproducts: flue gas desulfurization (FGD) spray dryer ash, Class C fly ash subbituminous coal combustion byproduct, and bauxite residue slurry from the alumina production process. Reactions were conducted in a closed, well-mixed (1,500 rpm) reactor with gas composed of 29.46% vol./vol. CO2 balanced by nitrogen gas (N2) fed at a rate of 300 mL/min. Reactions were carried out at ambient conditions. Results show linear relationships between caustic byproduct addition and CO2-bearing capacity, with relatively small impact of brine addition as compared to deionized water addition. FGD spray dryer ash/brine mixtures exhibited higher CO2 reactivity than those using Class C fly ash (0.759 moles CO2, at 23.6% solids by weight and 0.036 moles CO2 at 23.3% solids by weight, respectively). Bauxite residue exhibited moderate capacities in mixtures with higher percent solids (0.335 moles CO2 in 40% solids bauxite residue slurry). Carbonation capacity of caustic byproduct/acidic brine mixtures was shown to increase linearly with respect to percent caustic byproduct addition, but enhanced mineral carbonate precipitation resulting from synergistic reaction of brine cations with increased dissolved carbonate species was not observed in the short term.

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

Correlations are presented to compute the mutual solubilities of CO2 and chloride brines at temperatures 12–300°C, pressures 1–600 bar (0.1–60 MPa), and salinities 0–6 m NaCl. The formulation is computationally efficient and primarily intended for numerical simulations of CO2-water flow in carbon sequestration and geothermal studies. The phase-partitioning model relies on experimental data from literature for phase partitioning between CO2 and NaCl brines, and extends the previously published correlations to higher temperatures. The model relies on activity coefficients for the H2O-rich (aqueous) phase and fugacity coefficients for the CO2-rich phase. Activity coefficients are treated using a Margules expression for CO2 in pure water, and a Pitzer expression for salting-out effects. Fugacity coefficients are computed using a modified Redlich–Kwong equation of state and mixing rules that incorporate asymmetric binary interaction parameters. Parameters for the calculation of activity and fugacity coefficients were fitted to published solubility data over the P–T range of interest. In doing so, mutual solubilities and gas-phase volumetric data are typically reproduced within the scatter of the available data. An example of multiphase flow simulation implementing the mutual solubility model is presented for the case of a hypothetical, enhanced geothermal system where CO2 is used as the heat extraction fluid. In this simulation, dry supercritical CO2 at 20°C is injected into a 200°C hot-water reservoir. Results show that the injected CO2 displaces the formation water relatively quickly, but that the produced CO2 contains significant water for long periods of time. The amount of water in the CO2 could have implications for reactivity with reservoir rocks and engineered materials.

Wellbore flow model for carbon dioxide and brine

Abstract Wellbores have been identified as the most likely conduit for CO 2 and brine leakage from geologic carbon sequestration (GCS) sites, especially those in sedimentary basins with historical hydrocarbon production. In order to quantify the impacts of leakage of CO 2 and brine through wellbores, we have developed a wellbore simulator capable of describing non-isothermal open-well flow dynamics of CO 2 -brine mixtures. The mass and thermal energy balance equations are solved numerically by a finite difference scheme with wellbore heat transmission handled semi-analytically. This new wellbore simulator can take as input the pressure, saturation, and composition conditions from reservoir simulators and calculate CO 2 and brine fluxes needed to assess impacts to vulnerable resources. This new capability is being incorporated into the Certification Framework (CF) developed for risk assessment of GCS sites.

Thermochemical sulphate reduction in the Upper Devonian Cairn Formation of the Fairholme carbonate complex (South‐West Alberta, Canadian Rockies): evidence from fluid inclusions and isotopic data

AbstractThe Fairholme carbonate complex is part of the extensively dolomitized Upper Devonian carbonate reefs in west‐central Alberta. The studied formations contain moulds (up to 10 cm in diameter), which are filled partially with (saddle) dolomite, quartz and calcite cements. These cements precipitated from a mixture of brines that acquired high salinity by dissolution of halite and brines derived from evaporated sea water. The fluids were warm (homogenization temperature of primary fluid inclusions of 76 to 200 °C) and saline (20 to 25 wt% NaCl equivalent) and testify to thermochemical sulphate reduction processes. The latter is deduced from S in solid inclusions, CO2 and H2S in volatile‐rich aqueous inclusions and depleted δ13C values down to −26‰ Vienna Pee Dee Belemnite. High 87Sr/86Sr values (0·7094 to 0·7110) of the cements also indicate interaction of the fluids with siliciclastic sequences. The thermochemical sulphate reduction‐related cements probably formed during early Laramide burial. Another (younger) calcite phase, characterized by depleted δ18O values (−23·9‰ to −13·9‰ Vienna Pee Dee Belemnite), low Na (27 to 37 p.p.m.) and Sr (39 to 150 p.p.m.) concentrations and non‐saline (∼0 wt% NaCl equivalent) fluid inclusions, is attributed to post‐Laramide meteoric water.

Composition and evolution of fluids during skarn development in the Monte Capanne thermal aureole, Elba Island, central Italy

AbstractWe describe the chemistry of the fluids circulating during skarn formation by focusing on fluids trapped in calcsilicate minerals of the inner thermal aureole of the Late Miocene Monte Capanne intrusion of western Elba Island (central Italy). Primary, CH4‐dominant, C‐O‐H‐S‐salt fluid inclusions formed during prograde growth of the main skarn‐forming mineral phases: grossular/andradite and vesuvianite. The variable phase ratios attest to heterogeneous entrapment of fluid, with co‐entrapment of an immiscible hydrocarbon–brine mixture. Chemical elements driving skarn metasomatism such as Na, K, Ca, S and Cl, Fe and Mn were dominantly partitioned into the circulating fluid phase. The high salinity (apparent salinity between 58 and 70 wt% NaCl eq.) and the C‐component of the fluids are interpreted as evidence for a composite origin of the skarn‐forming fluids that involves both fluids derived from the crystallizing intrusion and contributions from metamorphic devolatilization. Oxidation of a Fe‐rich brine in an environment dominated by fluctuation in pressure from lithostatic to hydrostatic conditions (maintained by active crack‐sealing) contributed to skarn development. Fluid infiltration conformed to a geothermal gradient of about 100°C km−1, embracing the transition from high‐temperature contact metamorphism and fluid‐assisted skarn formation (at ca 600°C) to a barren hydrothermal stage (at ca 200°C).

Mobilization of ore fluids during Alpine metamorphism: evidence from hydrothermal veins in the Variscan basement of Western Carpathians, Slovakia

AbstractHydrothermal polymetallic veins of the Gemeric unit of the Western Carpathians are oriented coherently with the foliation of their low‐grade Variscan basement host. Early siderite precipitated from homogeneous NaCl‐KCl‐CaCl2‐H2O brines with minor CO2, while immiscible gas–brine mixtures are indicative of the superimposed barite, quartz–tourmaline and quartz–sulphide stages. The high‐salinity aqueous fluid (18–35 wt%) found in all mineralization stages corresponds to formation water modified by interaction with crystalline basement rocks at temperatures between 140 and 300°C. High brominity (around 1000 ppm in average) resulted from evaporation and anhydrite precipitation in a Permo‐Triassic marine basin, and from secondary enrichment by dissolution of organic matter in the marine sediments at diagenetic temperatures. Sulphate depletion reflects thermogenic reduction during infiltration of the formation waters into the Variscan crystalline basement. Crystallization temperatures of the siderite fill (140–300°C) and oxygen isotope ratios of the parental fluids (4–10‰) increase towards the centre of the Gemeric cleavage fan, probably as a consequence of decreasing water/rock ratios in rock‐buffered hydrothermal systems operating during the initial stages of vein evolution. In contrast, buoyant gas–water mixtures, variable salinities and strongly fluctuating P–T parameters in the successive mineralization stages reflect transition from a closed to an open hydrothermal system and mixing of fluids from various sources. Depths of burial were 6–14 km (1.7–4.4 kbar, in a predominantly lithostatic fluid regime) during the siderite and barite sub‐stages of the north‐Gemeric veins, and up to 16 km (1.6–4.5 kbar, in a hydrostatic to lithostatic fluid regime) in the quartz–tourmaline stage of the south‐Gemeric veins. The fluid pressure decreased down to approximately 0.6 kbar during crystallization of sulphides. U‐Pb‐Th, 40Ar/39Ar and K/Ar geochronology applied to hydrothermal muscovite–phengite and monazite, as well as cleavage phyllosilicates in the adjacent basement rocks and deformed Permian conglomerates corroborated the opening of hydrothermal veins during Lower Cretaceous thrusting and their rejuvenation during Late Cretaceous sinistral transpressive shearing and extension.

The Kinetics of Sulphate Deposition in Seeded and Unseeded Tests

Summary In a previous paper (Boak et al. 2005), we addressed the issue: What level of sulphate reduction is required to eliminate the need for scale inhibitor squeezing? In this earlier work, we developed the idea of a simple kinetic scheme for sulphate deposition on the basis of a "safe envelope" concept within which the system could operate. Central to the safe envelope approach is the choice of rate constant for barite deposition and this can be estimated experimentally under various conditions appropriate to the specific field application. Experimental results on kinetic barite deposition in low sulphate brine mixtures were presented previously (Boak et al. 2005). However, these previous results were carried out for unseeded solutions (i.e., no solid barite or sand particles were added to the scaling solutions). The following questions were raised If barite particles were present, would this mean that the solution supersaturation (Sp) would reduce to 1 very rapidly thus over-ruling any kinetic deposition effects? Does the presence of sand particles have the same effect as barite particles? In the case of both barite or sand particles does the size of the particles (i.e. the surface area per unit mass) have any effect on the barite deposition rate? In addition, a very simple kinetic model for bulk deposition of barite was used for which the long time behavior was that barite is deposited until the limiting ion was totally consumed. However, it is known that barite has some solubility at higher levels of sodium chloride and the kinetic model should limit to this value. This may be an important consideration especially in lower sulphate (or lower barium) brines. Experimental results are presented in this paper which both address and answer the above questions, and extend the analysis with an improved kinetic model for barite deposition. Even in the presence of seed materials (barite and sand of various surface areas), clear rate effects can be observed and rate constants can be derived. As expected, barite seed material of higher surface area induces faster depletion of the scaling ions to a supersaturation ratio of 1 than barite of lower surface area. However, allowing for the effect of surface area, the barite seed material shows a clearly enhanced potential to induce scale formation than the sand. In addition, the safe envelope model is extended by considering a more accurate analytical kinetic model which limits correctly to the equilibrium solubility of barite at long times.

Predicting PVT data for CO 2–brine mixtures for black-oil simulation of CO 2 geological storage

Accurate modeling of the storage or sequestration of CO 2 injected into subsurface formations requires an accurate fluid model. This can be achieved using compositional reservoir simulations. However, sophisticated equations of state (EOS) approaches used in current compositional simulators are computationally expensive. It is advantageous and possible to use a simple, but accurate fluid model for the very specific case of geological CO 2 storage. Using a black-oil simulation approach, the computational burden of flow simulation can be reduced significantly. In this work, an efficient and simple algorithm is developed for converting compositional data from EOS into black-oil PVT data. Our algorithm is capable of predicting CO 2–brine density, solubility, and formation volume factor, which are all necessary for black-oil flow simulations of CO 2 storage in geological formations. Numerical simulations for a simple CO 2 storage case demonstrate that the black-oil simulation runs are at least four times faster than the compositional ones without loss of accuracy. The accuracy in prediction of CO 2–brine black-oil PVT properties and higher computational efficiency of the black-oil approach promote application of black-oil simulation for large-scale geological storage of CO 2 in saline aquifers.

AVO as a fluid indicator: A physical modeling study

Information on time-lapse changes in seismic amplitude variation with offset (AVO) from a reservoir can be used to optimize production. We designed a scaled physical model experiment to study the AVO response of mixtures of brine, oil, and carbon dioxide at pressures of 0, 1.03, and [Formula: see text]. The small changes in density and velocity for each fluid because of increasing pressure were not detectable and were assumed to lie within the error of the experiment. However, AVO analysis was able to detect changes in the elastic properties between fluids that contained oil and those that did not. When the AVO response was plotted in the AVO intercept-gradient domain, fluids containing oil were clearly separated from fluids not containing oil. This was observed in the AVO response from both the top and base of the fluids in the physical model. We then compared the measured AVO response with the theoretical AVO response given by the Zoeppritz equations. The measured and theoretical AVO intercept responses for the top fluid reflection agree well, although the AVO gradients disagree slightly. For the fluid base reflection, the measured and theoretical responses are in close agreement.

Chemical evolution of saline waters in the Jordan-Dead Sea transform and in adjoining areas

The Ca–Mg relationship in groundwaters strongly points to the overall dolomitization and local albitization. The Mg/Ca ratios reveal two trends by which saline waters develop: increase of Mg/Ca ratio by evaporation and decreasing Mg/Ca ratios due to dolomitization and albitization. Br/Cl vs. Na/Cl ratios demonstrate that albitization does not play a major role which leaves dolomitization to be the main source for decreasing Mg/Ca ratios in saline waters. In the eastern and southern Region of Lake Kinneret, salinization occurs by mixing with a Ca/Mg molar ratio 1 dominates, which developed by the albitization of plagioclase in abundant mafic volcanics and the dolomitization of limestones. The most saline groundwater of the Tabgha-, Fuliya-, and Tiberias clusters could be regional derivatives of at least two mother brines: in diluted form one is represented by Ha’On water, the other is a Na-rich brine of the Zemah type. Additionally, a deep-seated Ca-dominant brine may ascend along the fractures on the western side of Lake Kinneret, which is absent on the eastern side. Groundwaters of the Lower Jordan Valley are chemically different on both sides of the Jordan River, indicating that the exchange of water is insignificant. All saline waters from the Dead Sea and its surroundings represent a complex mixture of brines, and precipitation and local dissolution of halite and gypsum. Many wells of the Arava/Araba Valley pump groundwater from the Upper Cretaceous limestone aquifer, the origin of the water is actually from the Lower Cretaceous Kurnub Group sandstones. Groundwater drawn from the Quaternary alluvial fill either originates from Kurnub Group sandstones (Eilat 108, Yaalon 117) or from altered limestones of the Judea Group. The origin of these waters is from floods flowing through wadis incised into calcareous formations of the Judea Group. On the other hand, as a result of step-faulting, hydraulic contact is locally established between the Kurnub- and the Judea Groups aquifers facilitating the inter-aquifer flow of the confined Kurnub paleowater into the karstic formations of the Judea Group. Two periods of Neogene brine formation are considered: the post-Messinan inland lagoon resulting in drying up of the Sdom Sea and the evaporation of the Pleistocene Samra Lake, which went further through the stage of Lake Lisan to the present Dead Sea. For the first period, major element hydrochemistry suggests that the saline waters and brines in the Jordan-Dead Sea–Arava Valley transform evolved from the gradual evaporation of an accumulating mixture of sea-, ground-, and surface water. Due to the precipitation of carbonates, gypsum, and halite, such an evaporating primary water body was strongly enriched in Mg, Br, and B and shows high molar ratios of Br/Cl, B/Cl, and Mg/Ca but low Na/Cl ratios. The development of the Br/Cl ratio is chemically modelled, showing that indeed brine development is explicable that way. Along with the evaporation brine, evaporites formed which are leached by infiltrating fresh water yielding secondary brines with Na/Cl ratios of 1. When primary brines infiltrated the sub-surface, they were subjected to Mg–Ca exchange in limestones (dolomitization) and to chloritization and albitization in basic igneous rocks turning them into Ca-Cl brines. These tertiary brines are omnipresent in the Rift. The brines of the late Lisan and Dead Sea were generated by evaporating drainage waters, which leached halite, gypsum, and carbonates from the soil and from the sub-surface. All these brines are still being flushed out by meteoric water, resulting in saline groundwaters. This flushing is regionally enhanced by intensive groundwater exploitation. In variable proportions, the Neogene and late Lisan Lake and Recent Dead Sea brines have to be considered as the most serious sources of salinization of groundwaters in the Rift. Deep-seated pre-Sdom brines cannot strictly be excluded, but if active they play a negligible role only.

A magmatic-hydrothermal transition in Arkaroola (northern Flinders Ranges, South Australia): from diopside–titanite pegmatites to hematite–quartz growth

A set of Palaeozoic diopside-titanite veins are present in Mesoproterozoic metagranites and metasediments that constitute the basement (Mt Painter Inlier) of the Adelaide Fold Belt (South Aus- tralia). These massive veins (up to 1 m) of pegmatitic nature contain large crystals of diopside, LREE-Y- enriched titanite (up to 40 cm in length) and minor amounts of quartz. They can be used to trace the sys- tem's development from a high-temperature magmatic stage through to a massive hydrothermal event. The pegmatitic origin of these veins is evident from a complex fluid-melt inclusion assemblage, consisting of a highly saline inhomogeneous fluid and relicts of melt. Immiscibility of melt and heterogeneous highly saline fluids (exceeding 61 eq. mass% NaCl) is preserved in primary inclusions in diopside and secondary inclusions in titanite, indicating relatively shallow conditions of formation (510 ± 20� C and 130 ± 10 MPa). Graphic intergrowth of diopside and albite occurs at the contact with granitic pegmatites. The system evolved into hydrothermal conditions, which can be deduced from a later population of only fluid inclusions (homogeneous and less saline, 40 eq. mass% NaCl), trapped around 350 ± 20� C and 80 ± 10 MPa. During quartz crystallization, the conditions moved across the halite liquidus resulting in a heterogeneous mixture of brine and halite crystals, which were trapped at 200 ± 20� C and 50 ± 10 MPa. Brecciation and a palaeo-geother- mal system overprinted the pegmatitic veins with an epithermal hematite-quartz assemblage and lesser amounts of bladed calcite and fluorite, in an intermit- tently boiling hydrothermal system of fairly pure H2O at 100-140� C and 1-5 MPa. Remobilization of LREEs and Y from titanite and/or the granitic host rock is evidenced by precipitation of apatite, allanite and wakefieldite in an intermediate stage. Occasional incorporation of radioactive elements or minerals, presumably U-rich, in the fluorite is responsible for radiolysis of H2 Ot o H 2.

Listeria monocytogenes Survival in Refrigerator Dill Pickles

Listeria monocytogenes can survive and grow in refrigerated foods with pH values of approximately 4.0 to 5.0 and salt concentrations of 3 to 4%. Home-fermented refrigerator dill pickles fit this description. Contamination of this product with L. monocytogenes could cause serious problems because these items are not heated prior to consumption. L. monocytogenes survival and growth patterns were investigated in refrigerator dill pickles at 1.3, 3.8, and 7.6% salt concentrations. Pickling cucumbers were dipped into an inoculum of L. monocytogenes, brine mixtures were added, and cucumbers were held at room temperature for 1 week and then refrigerated for up to 3 months. The pH, NaCl percentage, titratable acidity percentage, and total populations of Listeria and aerobic, psychrotrophic, and lactic acid bacteria were measured at the addition of brine, after 2, 4, and 7 days of storage at room temperature, and then weekly during refrigerated storage. The initial Listeria population was 5.4 to 5.6 log CFU/cm2 on cucumber surfaces and 3.9 to 4.6 log CFU/g internally. There was an approximate 0.3- to 1-log increase during room temperature fermentation followed by a population decline during refrigerator storage, with a greater decrease in the brines with the highest NaCl concentration. Up to 49 days, the internal tissue of pickles with 1.3, 3.8, or 7.6% salt concentrations were presumptively positive for L. monocytogenes by the enrichment method, and at 91 days the surfaces of such pickles were still positive for L. monocytogenes. Populations of total aerobes and lactic acid bacteria increased during room temperature storage and decreased gradually during refrigerated storage.

非水溶性ポリマー生産微生物ＣＪＦ‐００２による油層内流体のプロファイル・モディフィケーションに関する室内実験研究

Microbial EOR (MEOR) field test1∼4) was carried out in Fuyu oilfield, China. In this field test, Enterobacter sp. CJF-0027) which produced insoluble polymer was injected with nutrient, and oil production increased more than twice in volume because the high permeable zones were plugged with the polymer, and the water channeling was reduced8,9). Our research group carried out experimental studies to analyze the mechanisms of profile modification by the polymer produced by CJF-002.Firstly, 10m one-dimensional reservoir model was used for analyzing the polymer production behavior of CJF-002. CJF-002 was injected with nutrient and incubated. After the incubation, water was injected to observe the pressure of every 1m-point. As a result, high differential pressure was observed at the section of 0-1m and 3-4m. That is, CJF-002 produced the polymer at these section more actively. Moreover, it was suggested that a mixture of culture solution and brine improved pH of culture solution, and this improvement reactivated the polymer production of CJF-002 at the middle section (3-4m) and lower section.Secondly, network model was used for analyzing the effect of the polymer on profile modification. This model consisted of three 4m-low permeable sand-packs and one 4m-high permeable sand-pack. These sand-packs were reticulately jointed together at every 1m-point. CJF-002 was injected with nutrient from the central inlet and synthetic brine was injected from the other two inlets. Absolute permeability and flow rate of each section were calculated from the pressure observed at every jointing point. As a result, CJF-002 produced a significant amount of polymer in all the high permeable hose and the permeability of high permeable hoses decreased to approximately 1/2 of original permeability. Consequently, the flow rate of high permeable hoses decreased and that of low permeable hoses increased. It showed that the polymer produced by CJF-002 was effective on the profile modification.