Reservoir Formation Water Research Articles

CO2–Water–Rock Interaction and Its Influence on the Physical Properties of Continental Shale Oil Reservoirs

Shale oil resources are abundant, but reservoirs exhibit strong heterogeneity with extremely low porosity and permeability, and their development is challenging. Carbon dioxide (CO2) injection technology is crucial for efficient shale oil development. When CO2 is dissolved in reservoir formation water, it undergoes a series of physical and chemical reactions with various rock minerals present in the reservoir. These reactions not only modify the reservoir environment but also lead to precipitation that impacts the development of the oil reservoir. In this paper, the effects of water–rock interaction on core porosity and permeability during CO2 displacement are investigated by combining static and dynamic tests. The results reveal that the injection of CO2 into the core leads to reactions between CO2 and rock minerals upon dissolution in formation water. These reactions result in the formation of new minerals and the obstruction of clastic particles, thereby reducing core permeability. However, the generation of fine fractures through carbonic acid corrosion yields an increase in core permeability. The CO2–water–rock reaction is significantly influenced by the PV number, pressure, and temperature. As the injected PV number increases, the degree of pore throat plugging gradually increases. As the pressure increases, the volume of larger pore spaces gradually decreases, resulting in an increase in the degree of pore blockage. However, when the pressure exceeds 20 MPa, the degree of carbonic acid dissolution will be enhanced, resulting in the formation of small cracks and an increase in the volume of small pores. As the temperature reaches the critical point, the degree of blockage of macropores gradually increases, and the blockage of small pores also occurs, which eventually leads to a decrease in core porosity.

Simulation of pore space production law and capacity expansion mechanism of underground gas storage

One-dimensional gas injection storage building and one-cycle injection-production modeling experiment, and two-dimensional flat core storage building and multi-cycle injection-production modeling experiment were carried out using one-dimensional long core and large two-dimensional flat physical models to find out the effects of reservoir physical properties and injection-production balance time on reservoir pore utilization efficiency, effective reservoir capacity formation and capacity-reaching cycle. The results show that reservoir physical properties and formation water saturation are the main factors affecting the construction and operation of gas-reservoir type underground gas storage. During the construction and operation of gas-reservoir type gas storage, the reservoir space can be divided into three types of working zones: high efficiency, low efficiency and ineffective ones. The higher the reservoir permeability, the higher the pore utilization efficiency is, the smaller the ineffective working zone is, or there is no ineffective working zone; the smaller the loss of injected gas is, and the higher the utilization rate of pores is. The better the reservoir physical properties, the larger the reservoir space and the larger the final gas storage capacity is. The higher the water saturation of the reservoir, the more the gas loss during gas storage capacity building and operation is. Optimizing injection-production regime to discharge water and reduce water saturation is an effective way to reduce gas loss in gas storage. In the process of multiple cycles of injection and production, there is a reasonable injection-production balance time, further extending the injection-production balance period after reaching the reasonable time has little contribution to the expansion of gas storage capacity.

Electrochemically Enhanced Deposition of Scale from Chosen Formation Waters from the Norwegian Continental Shelf

Reservoir formation waters typically contain scaling ions which can precipitate and form mineral deposits. Such mineral deposition can be accelerated electrochemically, whereby the application of potential between two electrodes results in oxygen reduction and water electrolysis. Both processes change the local pH near the electrodes and affect the surface deposition of pH-sensitive minerals. In the context of the plugging and abandonment of wells, electrochemically enhanced deposition could offer a cost-effective alternative to the established methods that rely on setting cement plugs. In this paper, we tested the scale electro-deposition ability of six different formation waters from selected reservoirs along the Norwegian continental shelf using two experimental setups, one containing CO2 and one without CO2. As the electrochemical deposition of scaling minerals relies on local pH changes near the cathode, geochemical modelling was performed to predict oversaturation with respect to the different mineral phases at different pH values. In a CO2-free environment, the formation waters are mainly oversaturated with portlandite at pH > 12. When CO2 was introduced to the system, the formation waters were oversaturated with calcite. The presence of mineral phases was confirmed by powder X-ray diffraction (XRD) analyses of the mineral deposits obtained in the laboratory experiments. The geochemical-modelling results indicate several oversaturated Mg-bearing minerals (e.g., brucite, dolomite, aragonite) in the formation waters but these, according to XRD results, were absent in the deposits, which is likely due to the significant domination of calcium-scaling ions in the solution. The amount of deposit was found to be proportional to the concentration of calcium present in the formation waters. Formation waters with a high concentration of Ca ions and a high conductivity yielded more precipitate.

An improved simple correlation for accurate estimation of CO2-Brine interfacial tension at reservoir conditions

A newly developed CO2−brine interfacial tension (IFT) correlation has been successfully developed to more accurately estimate the CO2−brine IFT for a wide range of reservoir pressure, temperature, and formation water salinity. The new CO2−brine correlation is expressed as a function of CO2-water density difference (function of pressure and temperature), temperature, and the valence-weighted molality of the cations. The novel aspect of the approach was to both correlate with density difference and include accurate temperature dependence of the parameters. This prediction model originated from a CO2−brine IFT database from the literature that covers 1298 CO2−brine IFT data including 484 for pure water and CO2. To examine its predictive capacity, the new CO2−brine IFT correlation is compared with four commonly used IFT correlations in the literature. It is found that the new CO2−brine IFT correlation provides more comprehensive and accurate reproduction of the literature pure CO2−pure water IFT data with an average absolute relative error (AARE) of 2.4% and standard deviation (SD) of 3.2%. In addition, the newly developed CO2−brine IFT correlation results in the accurate prediction of the CO2−brine IFT with an AARE of 2.4% and a SD of 3.4%.

Effect of formation water salinity on interfacial tension of reservoir fluids

The interaction of surface-active species within crude oil with ions in the aqueous phase can have a major influence on the interfacial tension (IFT) between these two phases. Herein, the influence of salinity on IFT is investigated systematically. Brines with different salinities, including seawater and reservoir formation water, are considered. The measurements clearly show distinct IFT trends depending on the composition and concentration of salts in the aqueous phase as well as on the crude oil chemical species, as represented by the API values. The results show that complex brine systems have a stronger effect on IFT than individual single salt brine systems. It is possible to derive distinct additive correction factors for the respective tested brine systems based on the averaged values of deviation from the respective cases in deionized water. On average for the tested 10 oils, and in comparison to measurements in DI water, IFT was reduced by 3.4 mN/m in 100 kppm CaCl 2 solution, by 5.3 mN/m in 100 kppm NaCl solution, by 6.8 mN/m in formation water and by 8.2 mN/m in seawater. • Systematic investigation of salinity influence on IFT. • Single salt solutions, seawater and formation water considered. • Light, medium and heavier oils analysed. • Stronger IFT reduction in presence of complex brines. • IFT correction factors suggested.

A New Coupled Model for Permeability-Impairment Prediction Because of Mineral Scale Deposition in Water-Injection Wells

Summary It is common to produce some percentage of water during the oil-extraction process. Conventionally, some water-disposal wells are drilled in an oil field to inject these useless and hazardous waters. Mineral scale formation is a critical issue in water-injection wells and may result in well plugging and an injection rate decrease in these wells. The two steps of mineral scale formation are scale precipitation and scale deposition. Two main mechanisms of inorganic scale precipitation are incompatibility between injected water and reservoir formation water and changes in the thermodynamic state of injected water. The injectivity of the well decreases because of deposition of supersaturated precipitated scales through the well column and near-wellbore region. Currently, limited research has been done to evaluate inorganic scale deposition, and most of the research is limited to calculation of total scaling by commercial software. In this study, the mineral scale precipitation is evaluated by software modeling and laboratory experiments in an Iranian oil field, and the effect of the scale deposition phenomenon is assessed on permeability impairment and injection rate decrease. One of the major novelties of this work is simulation of various scale-deposition models by coupling MATLAB® software coding and a reservoir simulator. The accuracy of different deposition models is analyzed by comparing them with field data (real water-injection well) and laboratory tests (coreflooding test). Finally, our simulation results show that a single deposition model could not exactly predict the scaling phenomena in the studied carbonate reservoir that is supersaturated with CaCO3 and CaSO4. It is recommended to improve the scale-formation prediction with a mixed deposition model supported by reliable static/dynamic modeling and experimental analysis.

Sandstone Reservoir Wettability Alteration Due to Water Softening: Impact of Silica Nanoparticles on Sand Production Mechanism

Low salinity water in the oil reservoirs changes the wettability and increases the oil recovery factor. In sandstone reservoirs, the sand production occurs or intensifies with wettability alteration due to low salinity water injection. In any case, sand production should be stopped and there are many ways to prevent sand production. By modifying the composition of low salinity water, it can be adapted to be more compatible with the reservoir rock and formation water, which has the least formation damage. By eliminating magnesium and calcium ions, smart soft water (SSW) is created which is economically suitable for injection into the reservoirs. By stabilizing the nanoparticles in SSW, nanofluids can be prepared which with injection into the sandstones reservoir increase the oil recovery, change the wettability and increase the rock strength. In this present, SSW composition was determined by compatibility testing, and the SiO2 nanoparticle with 1000 ppm concentration was stabilized in SSW. Eight thin sections were oil wetted by using normal heptane solution and different molars of stearic acid and two thin sections were considered as base thin sections to compare the effect of wettability alteration on sand production. Thin sections were immersed in SSW and Nanofluid, the amount of contact angle and sand production were measured in both cases. The amount of sand produced and the contact angle in SSW was higher than the Nanofluid. The silica nanoparticles reduced the contact angle (more water wetting) and by sitting between the sand particles, more than 40%, it reduced sand production.

Investigation of rock and fluid interactions during engineered water flooding in dolomite reservoir rocks

ABSTRACT Engineered water (EW) flooding is one of the enhanced oil recovery (EOR) techniques in carbonate reservoirs. In this method, the wettability of reservoir rock is altered by controlling the amount of various ions in the injected brine. The thermodynamics of wettability is related to the surface interactions and stability of water film on a rock surface. It can be identified by calculating disjoining pressure isotherms. In this study, core flooding tests, contact angle and zeta potential measurements along with the disjoining pressure isotherm calculation by the DLVO theory were used to investigate the wettability alteration of dolomite rock. Four brines include reservoir formation water (RFW), sea water (SW) and two engineered water (LSW1 and LSW2) were used as injected fluid. The results show that the ionic strength of the dolomite rock depends on the electrical charge at the brine-rock-crude oil interfaces, as, the presence of divalent ions such as SO4 2- in injected brine led to the repulsive interaction of rock-brine and brine-crude oil interfaces. Also, the disjoining pressure isotherms indicate the water film thickness on the dolomite rock surfaces was increased by using the sea water and two engineered water. This thickness at the LSW2 is about 1.6 times thicker than the LSW1, while in comparison to the SW, the thickness of the film is almost 2 times higher than. Based on the results, the double-layer expansion (DLE) is a mechanistic mechanism in which the wettability alteration of the dolomite rocks.

Experimental investigation of smart carbonated water injection method in carbonates

AbstractEnhanced oil recovery (EOR) has been noticed during recent years from reservoirs that are at the end of their life plateau or in which production has been declined. Two of these EOR methods are as follows: carbonated water and smart water injection. In carbonated water injection method, CO2‐contained water is injected in reservoirs in order to decrease free CO2 injection mobility, increase water viscosity, and store/remove produced greenhouse CO2 gas safely, and in smart water injection method, the ions in brine are modified in order to make controlled reactions with distributed ions on the surface of rock to cause more hydrocarbon recovery. In this paper, the combination of these two methods is investigated as hybrid smart carbonated water injection to find out the recovery factor change and effective mechanisms. Experimental core flooding setup is used for investigation of hybrid EOR injection applicability and mechanisms. Probable mechanisms are measured using different cores and five water samples are used for preparing carbonated water (at pressure of 2500 psi) including sea water (34 261 ppm), river water (1329 ppm), one of Iranian reservoir formation water (FW) (163 711 ppm), 10 times diluted FW (0.1 FW), and 100 times diluted FW (0.01 FW). The effect of both brine content and volume of CO2 is determined during hybrid EOR assessment. The main mechanisms activated including pH variation, oil swelling, oil viscosity reduction, ion concentration variation in brine and porous media, and wettability alteration have been investigated. Hybrid method resulted in highest recovery (70%) mainly due to ion exchange, wettability alteration, oil swelling, and permeability enhancement. In addition, type of salt concentration will affect recovery as 0.01 FW results in 8% and 16% additional oil recovery compared to sea and river waters, respectively. Coupling of CO2 and salts will increase recovery factor due to mechanisms activated by each of these factors as 0.01 FW results in 10% more oil recovery compared to FW. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Experimental investigation of the performance of biosurfactant to wettability alteration and interfacial tension (IFT) reduction in microbial enhanced oil recovery (MEOR)

In this Study, the biosurfactant production potential of Enterobacter Cloacae and Enterobacter Hormaechei microorganisms that were isolated from one of the oil reservoir formation water located in the southwest of Iran was explored. The produced biosurfactant caused substantial surface tension reduction of the growth medium and interfacial tension reduction between oil and brine to 31 and 3.2 mN/m from the original value of 72 and 29 mN/m respectively. In addition, the impact of other parameters such as temperature and salinity were investigated by performing appropriate experiments. The results show that the wettability alteration toward neutrally wet conditions could be the dominant mechanism on the improvement of oil recovery and the adsorption of bacteria cells and forming biofilm was the main contributor to this wettability alteration.

A perforated electrode design for passivation reduction during the electrochemical treatment of produced water

Produced water refers to the water that is generated when oil and gas are extracted from the ground, and it usually includes the natural water layer within the reservoir (formation water) as well as the injected water. The generation of these large amounts of produced water represents a major environmental and economic challenge to the Oil and Gas Industry. Although many studies have attempted addressing this challenge, there has not been any significant development in the treatment of produced water, and most of these studies have achieved limited success. This work introduces a novel electrocoagulation cell for the treatment of produced water, with the aim of reducing electrode passivation, which has always been considered as a bottleneck in the electrochemical treatment of contaminated water. The main goal of the study is to develop an effective perforated electrode design that can reduce cathode passivation and consequently reduce energy consumption. The novel cell design has been tested and optimized for the treatment of produced water to reduce the concentration of the major organic contaminants in the water. The contaminants reduction efficiency of the proposed design was evaluated and benchmarked with multiple cell configurations. The perforated electrode was superior to other configurations and effective in mitigating passivation, reducing the energy consumption by about 70 % compared to the typical plate electrode. The cell performance was optimized, using response surface methodology, and then operated continuously to evaluate the electrocoagulation efficiency. The new cell design achieved a steadystate reduction of the organic contaminants in the produced water by up to 97 %, 98 % and 95 % for TOC, TPH and O&G, respectively.

Effect of SO4−2 ion exchanges and initial water saturation on low salinity water flooding (LSWF) in the dolomite reservoir rocks

The low salinity water injection has become one of the most important studies in the oil industry for improving oil recovery compared to conventional seawater injection. Thus, extensive studies have been conducted in carbonate and sandstone reservoirs to investigate how the physical properties of rocks and the chemical composition of fluids influence low salinity effect, while, the carbonate reservoir rocks requires more investigation of the effect of molecular and/or ionic interactions. In this experimental work, the effectiveness of various water flooding schemes in carbonate reservoir rock samples is investigated. In this regard, the oil recovery potential of seawater (SW), reservoir formation water (RFW) and managed water salinity (MWS), with different ion compositions adjusted based on the formation water composition are used. The experiments have been performed on the dolomite core samples and crude oil from an Iranian oil reservoir. Various measurements including zeta potential, XRD, contact angle and interfacial tension have been planned. The main contribution is to investigate the effect of both brine’s ionic composition and rock’s initial water saturation on wettability change and oil recovery. The results show that, the concentration of ion in the injected water must be managed over an optimum range for each case. This results in changing the wettability of carbonate rock to a less oil-wetting state by altering the brine composition and reducing the salinity. Moreover, initial water saturation plays a role in the process, so that, by increasing content in optimum range, the oil recovery increased.

An ion–salt complex of rocks from the Bazhenov formation of West Siberia

The results of experimental studies on the macro- and microcomponent composition of the ion–salt complex of argillaceous siliceous rocks from the Bazhenov formation of West Siberia are presented. The studies were based on the analysis of samples using a high-resolution mass spectrometer with ionization in inductively coupled plasma, by the X-ray diffraction (XRD) method, and via the study of water and ammonium extracts from samples with a natural moisture content, as well as after drying. It was established that the composition of the solutions of water extracts from rocks with a natural moisture content belongs to the sulfate- sodium-bicarbonate type with increased content of dissolved silicic acid with weakly alkaline pH values (∼9.5) and is considerably different from the content of water extracts from the samples after drying. Sodium dominates in the exchange complex; the cation exchange capacity is 14–19 mg-eq/100 g of rock. A sharp excess of the percentage abundance by 2–10 orders of magnitude was recorded for barium, boron, zinc, vanadium, uranium, and arsenic. The barium content in pore water exceeds the strontium content by a factor of 10, which is anomalous with respect to the reservoir formation waters in the majority of oil fields and to the ocean water.

Medium factors on anaerobic production of rhamnolipids by Pseudomonas aeruginosa SG and a simplifying medium for in situ microbial enhanced oil recovery applications.

Aerobic production of rhamnolipid by Pseudomonas aeruginosa was extensively studied. But effect of medium composition on anaerobic production of rhamnolipid by P. aeruginosa was unknown. A simplifying medium facilitating anaerobic production of rhamnolipid is urgently needed for in situ microbial enhanced oil recovery (MEOR). Medium factors affecting anaerobic production of rhamnolipid were investigated using P. aeruginosa SG (Genbank accession number KJ995745). Medium composition for anaerobic production of rhamnolipid by P. aeruginosa is different from that for aerobic production of rhamnolipid. Both hydrophobic substrate and organic nitrogen inhibited rhamnolipid production under anaerobic conditions. Glycerol and nitrate were the best carbon and nitrogen source. The commonly used N limitation under aerobic conditions was not conducive to rhamnolipid production under anaerobic conditions because the initial cell growth demanded enough nitrate for anaerobic respiration. But rhamnolipid was also fast accumulated under nitrogen starvation conditions. Sufficient phosphate was needed for anaerobic production of rhamnolipid. SO4(2-) and Mg(2+) are required for anaerobic production of rhamnolipid. Results will contribute to isolation bacteria strains which can anaerobically produce rhamnolipid and medium optimization for anaerobic production of rhamnolipid. Based on medium optimization by response surface methodology and ions composition of reservoir formation water, a simplifying medium containing 70.3 g/l glycerol, 5.25 g/l NaNO3, 5.49 g/l KH2PO4, 6.9 g/l K2HPO4·3H2O and 0.40 g/l MgSO4 was designed. Using the simplifying medium, 630 mg/l of rhamnolipid was produced by SG, and the anaerobic culture emulsified crude oil to EI24 = 82.5 %. The simplifying medium was promising for in situ MEOR applications.

Evaluation of Different Artificial Intelligent Models to Predict Reservoir Formation Water Density

Nearly all hydrocarbon reservoirs are bounded by water-saturated rocks, namely aquifers. In addition to natural water drive, there is an artificial water drive mechanism in which water is injected into formation to intensify the reservoir pressure. This method, employed to induce the hydrocarbon production, is called water flooding. Several laboratory researches have shown that oil recovery can be heightened by making some alterations to injected brine salinity through water flooding. Accordingly, acquiring exact information about the PVT characteristics of brine is necessary. Density is a property of great importance as it is employed in various physical, chemical, geothermal, and geochemical aspects. The authors aimed to develop a dependable intelligent method to accurately predict the brine density at elevated temperatures and pressures. MLP and GA-RBF models were utilized in this study. The results showed that the proposed model is capable of accurately predicting the brine density at elevated pressures and temperatures for different concentrations of brine. The correlation factor of 1.0000 and root mean squared error of 3.27E-05 demonstrate the accuracy of the proposed model.

Flow-through experiments on water–rock interactions in a sandstone caused by CO2 injection at pressures and temperatures mimicking reservoir conditions

Flow-through experiments were performed in a newly designed experimental setup to study the water–rock interactions caused by CO2 injection in sandstones obtained from the Altmark natural gas reservoir under the simulated reservoir conditions of 125°C and 50bar CO2 partial pressure. Two different sets of experiments were conducted using CO2-saturated millipore water and CO2-saturated brine (41.62gL−1 NaCl and 31.98gL−1 CaCl2·2H2O), mimicking the chemical composition of the reservoir formation water. The major components in the sandstone were quartz (clasts+cement), feldspars, clay minerals (illite and chlorite), and cements of carbonates and anhydrite. Fluid analysis suggested the predominant dissolution of anhydrite causing increased concentrations of calcium and sulfate at early time periods at non-equilibrium geochemical conditions. The Ca/SO4 molar ratio (>1) indicated the concurrent dissolution of both calcite and anhydrite. Dissolution of feldspar and minor amounts of clay (chlorite) was also evident during the flow-through experiments. The permeability of the sample increased by a factor of two mostly due to the dissolution of rock cements during brine injection. Geochemical modeling suggests calcite dissolution as the major buffering process in the system. The results may in future studies be used for numerical simulations predicting CO2 storage during injection in sandstone reservoirs.

Low-Temperature Oxidation and Characterization of Heavy Oil via Thermal Analysis

High pressure air injection (HPAI) without ignition has attracted extensive attention in the air injection based improved oil recovery (IOR) process for light oil reservoirs but was rarely proposed as an IOR process for heavy oil reservoirs. This study aims at evaluating the potential of HPAI without ignition for deep, high pressure, heavy oil reservoirs (Tahe oilfield, Tarim Basin, China). Many low-temperature oxidation (LTO) experiments were carried out to study the oxidation behavior of heavy oil under the reservoir conditions (120 °C, about 30–40 MPa) using an isothermal oxidation reactor. The produced gases were analyzed using gas chromatography for their content of O2, CO2, CO, and hydrocarbon gas (C1–C6) content. The apparent hydrogen/carbon (H/C) and molar ratio of the carbon oxides (m-ratio) were also calculated from effluent gases to analyze oxidation behavior. The effects of quartz, reservoir core (characterized by X-ray diffraction), formation water, and catalyst on LTO were analyzed. Thermogravimetry (TG-DTG) experiments were conducted to characterize the oxidation behavior and kinetics of heavy oil. The Arrhenius method was employed to calculate reaction activation energy. The isothermal oxidation experimental results show that reservoir core, formation water, and catalyst have important influences on LTO. The upgrading of heavy oil occurred in the presence of catalyst. The inflammable coke was formed, and combustion reaction happened at 40 MPa and 120 °C after oxidation for 7 days, which implies heavy oils have a spontaneous combustion potential for HPAI without ignition process in Tahe heavy oil reservoir. Simultaneously, the heavy oil upgrading indicates that HPAI without ignition process in the presence of catalyst is a promising and potential air injection based IOR technique for deep, high pressure, heavy oil reservoirs such as the Tahe oilfield.

Life in the slow lane; biogeochemistry of biodegraded petroleum containing reservoirs and implications for energy recovery and carbon management.

Our understanding of the processes underlying the formation of heavy oil has been transformed in the last decade. The process was once thought to be driven by oxygen delivered to deep petroleum reservoirs by meteoric water. This paradigm has been replaced by a view that the process is anaerobic and frequently associated with methanogenic hydrocarbon degradation. The thermal history of a reservoir exerts a fundamental control on the occurrence of biodegraded petroleum, and microbial activity is focused at the base of the oil column in the oil water transition zone, that represents a hotspot in the petroleum reservoir biome. Here we present a synthesis of new and existing microbiological, geochemical, and biogeochemical data that expands our view of the processes that regulate deep life in petroleum reservoir ecosystems and highlights interactions of a range of biotic and abiotic factors that determine whether petroleum is likely to be biodegraded in situ, with important consequences for oil exploration and production. Specifically we propose that the salinity of reservoir formation waters exerts a key control on the occurrence of biodegraded heavy oil reservoirs and introduce the concept of palaeopickling. We also evaluate the interaction between temperature and salinity to explain the occurrence of non-degraded oil in reservoirs where the temperature has not reached the 80–90°C required for palaeopasteurization. In addition we evaluate several hypotheses that might explain the occurrence of organisms conventionally considered to be aerobic, in nominally anoxic petroleum reservoir habitats. Finally we discuss the role of microbial processes for energy recovery as we make the transition from fossil fuel reliance, and how these fit within the broader socioeconomic landscape of energy futures.

A comparison of standard thermodynamic properties and solubility data for baryte, Ba2+(aq) and SO42–(aq)

The thermodynamic solubility product for baryte, determined at standard conditions, from data in commonly used compilations, was compared with published experimental solubility products for baryte and with the solubility products from databases used by the PHREEQC geochemical speciation code and MultiScale, which is often used by oil companies to predict or describe baryte scaling. The values in the various databases agree well with experimental data (10–10.05–10–9.96; Melcher, 1910; Neuman, 1933; Templeton, 1960; Davis and Collins, 1971; Blount, 1977; Felmy et al., 1990), which agree within uncertainty with the values presented in the compilations of Robie et al. (1979), Wagman et al. (1982), Lide (2005), Raju and Atkinson (1988), as well as Nordstrom and Munoz (1994), whose values have the least uncertainty. In solutions of 50% seawater mixed with 50% reservoir formation waters, the data predict baryte supersaturation, both at standard temperature and at the temperatures expected in the reservoir, completely consistent with field observations. This provides confidence that the Pitzer approach for activity correction and the database is valid for investigations of baryte precipitation rates in high ionic strength solutions.

Determination of the stable isotope composition and total dissolved solids of Athabasca oil sands reservoir porewater: Part 2. Characterization of McMurray Formation waters in the Suncor–Firebag field

A new stable isotope approach was used to determine the total dissolved solids concentration and stable isotope composition for oil sands drill core extracted porewater at the Suncor–Firebag oil sands field in northeastern Alberta, Canada. A stable isotope mixing approach was used to correct for contamination by drilling fluids in the porewater samples. The mean isotopic compositions of oxygen () and hydrogen () in water for fluid samples from 12 wells at Firebag were −20.5 ± 1.4‰ and −157 ± 11‰, respectively. The mean total dissolved solids (TDS) concentration of the reservoir formation water in 12 sampled wells was 1100 ± 400 mg/L (1σ). These results suggest that the McMurray Formation water at Firebag is primarily derived from Holocene groundwater recharge, and that the water within the bitumen reservoir is similar to groundwater well samples obtained within the McMurray Formation at Firebag. The results obtained in this study are consistent with regional trends and previously proposed local hydrogeological flow conditions.