The low-salinity effect (LSE) in carbonate rock has been less explored in comparison to sandstone rock. Laboratory experiments have shown that brine composition and (somewhat reduced) salinity can have a positive impact on oil recovery in carbonates. However, the mechanism leading to improved oil recovery in carbonate rock is not well understood. Several studies showed that a positive low-salinity flooding (LSF) effect might be associated with dissolution of rock; however, because of equilibration, dissolution may not contribute at reservoir scale, which would make LSF for carbonate rock less attractive for field applications. This raises now the question whether calcite dissolution is the primary mechanism of the LSF effect. In this paper, we aim to first demonstrate the positive response of carbonate rock to low salinity and then to gain insight into the underlying mechanism(s) specific to carbonate rock. We followed a similar methodology as in sandstone rock [Mahani, H.; Berg, S.; Ilic, D.; Bartels, W....

Insights into the Mechanism of Wettability Alteration by Low-Salinity Flooding (LSF) in Carbonates

Our understanding of the phylogenetic diversity, metabolic capabilities, ecological roles, and community dynamics of oil reservoir microbial communities is far from complete. The lack of appreciation of the microbiology of oil reservoirs can lead to detrimental consequences such as souring or plugging. In contrast, knowledge of the microbiology of oil reservoirs can be used to enhance productivity and recovery efficiency. It is clear that (1) nitrate and/or nitrite addition controls H2S production, (2) oxygen injection stimulates hydrocarbon metabolism and helps mobilize crude oil, (3) injection of fermentative bacteria and carbohydrates generates large amounts of acids, gases, and solvents that increases oil recovery particularly in carbonate formations, and (4) nutrient injection stimulates microbial growth preferentially in high permeability zones and improves volumetric sweep efficiency and oil recovery. Biosurfactants significantly lower the interfacial tension between oil and water and large amounts of biosurfactant can be made in situ. However, it is still uncertain whether in situ biosurfactant production can be induced on the scale needed for economic oil recovery. Commercial microbial paraffin control technologies slow the rate of decline in oil production and extend the operational life of marginal oil fields. Microbial technologies are often applied in marginal fields where the risk of implementation is low. However, more quantitative assessments of the efficacy of microbial oil recovery will be needed before microbial oil recovery gains widespread acceptance.

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Microbial processes in oil fields: culprits, problems, and opportunities.

Supercritical fluid extraction (SCFE), based on the utilization of a fluid under supercritical conditions, is a technology suitable for extraction and purification of a variety of compounds, particularly those that have low volatility and/or are susceptible to thermal degradation. The interest in SCFE is promoted by legal limitations of conventional solvents for food and pharmaceutical uses. The physicochemical properties of supercritical CO2 (higher diffusivity, lower viscosity, and lower surface tension than conventional solvents) facilitate mass transfer and allow an environmentally friendly operation. This article presents a comprehensive compilation of data on the supercritical CO2 extraction of antioxidant compounds from vegetal materials, with particular attention to those of a phenolic nature. Aspects concerning the supercritical operation for extraction and fractionation of antioxidants compounds are considered, including equilibrium solubility of pure compounds and effects of the operational con...

Supercritical CO2 extraction and purification of compounds with antioxidant activity.

Electrokinetics of Carbonate/Brine Interface in Low-Salinity Waterflooding: Effect of Brine Salinity, Composition, Rock Type, and pH on ζ-Potential and a Surface-Complexation Model

A comprehensive review of low salinity/engineered water injections and their applications in sandstone and carbonate rocks

Low-salinity waterflooding has been used to improve oil recovery for many decades. Several theories regarding the mechanism of low-salinity flooding have been discussed in the literature including interfacial tension reduction, wettability alteration, change in pH value, emulsion formation, and clay migration. This work presents the results of flooding tests on selected carbonate core samples taken from Bu Hasa field in Abu Dhabi using sea water and two field injection waters, Um-Eradhuma (UER) at 197,357 ppm and Simsima at 243,155 ppm. These results were used to evaluate the effects of brine salinity and ionic composition on the possible interactions of limestone rock/brine/and oil system and to identify the oil recovery mechanism. The field injection waters were diluted to salinities of 5,000 and 1,000 ppm and the optimum salinity was determined and then modified by varying the sulfate and calcium ion concentrations. Wettability alteration was determined by contact angle measurements. Interfacial tension measurements of the studied systems were also performed in an attempt to evaluate the flow mechanism with low-salinity flooding. The experimental results revealed that a significant improvement in the oil recovery can be achieved through alteration of the injection water salinity. Reducing the salinity of UER water from 197,357 to 5,000 ppm resulted in an improvement of oil recovery from 63 to 84.5 % of OOIP and the latter salinity was used to evaluate the impact of changing the sulfate and calcium ion concentrations on oil recovery. Results also indicated that sulfate concentration has a significant effect on the flooding process and that increasing the sulfate concentration beyond some optimum concentration of 46.8 ppm resulted in a negative effect on the flooding process. Contact angle measurements indicated that lowering the solution salinity could shift the wettability of the system towards intermediate wettability levels and that the UER water exhibits higher shift toward intermediate wettability compared to other waters. Results also indicated that there is no clear correlation between the improvements in oil recovery and interfacial tension and the pH of the studied systems. The results of this work are useful for people working in this field.

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Low-salinity flooding in a selected carbonate reservoir: experimental approach

Asphaltene precipitation and deposition in the near wellbore region: a modeling approach

Current empirical correlations to evaluate crude oil PVT properties are based on data from different parts in the world and are more accurate for use with crudes from the same basins for which the data was correlated. Standing correlation, for example, used California crudes. Glaso's used North Sea crudes. Al-Marhoun's used Middle East crudes. Petrosky and Farshad used Gulf of Mexico crudes, and Dokla and Osman produced a correlation based on UAE offshore crude oil samples. A few other correlations were based on a very large number of samples from different regions. The most widely used of these is the Vasquez and Beggs correlation. The universal correlations, however, are less accurate than regional correlations, when they are available, because of the scatter involved by using a large number of data. The UAE fields are very significant and constitute around 10% of reserves worldwide. In this work, experimental PVT measurements from around 15 reservoirs located in the UAE were used to test the validity of commonly used PVT correlations. The data then was used to construct a new set of empirical correlations which were also tested against the experimental values. Results indicate that the new correlations reduced the error involved in estimating the bubble point pressures and the oil formation volume factor to within less than half the range of error associated with commonly used correlations when compared to experimental values. The physical properties correlated include the oil formation volume factor at the bubble point, the bubble point pressure, the oil compressibility (in order to get the oil formation volume factor above the bubble point pressure), and the oil viscosity at the bubble point and above the bubble point.

Reyadh A. Almehaideb

Papers

Low-salinity flooding in a selected carbonate reservoir: experimental approach

Asphaltene precipitation and deposition in the near wellbore region: a modeling approach

Improved PVT correlations for UAE crude oils

Representation of solid-supercritical fluid phase equilibria using cubic equations of state

EOS tuning to model full field crude oil properties using multiple well fluid PVT analysis