Implications of microbial enhanced oil recovery and waterflooding for geochemical interpretation of recovered oils.

Biosurfactants and waterflooding have been widely reported thus far for enhancing oil production. Nevertheless, there is a lack of literature to explore enhanced oil recovered methods effects on its chemical composition. The aim of this work is to investigate the effects of a biosurfactant produced by Bacillus safensis and brine injection on the recovered petroleum composition, and their implications for geochemical interpretation. Original and oils recovered from displacement tests were analyzed by gas chromatography and ultra-high-resolution mass spectrometry, emphasizing saturated and aromatic biomarkers and basic and acidic polar compounds. Geochemical parameters based on some saturated compounds were subtly affected by the recovery methods, showing their reliable applicability in geochemical studies. Contrarily, parameters based on some aromatic compounds were more affected by biosurfactant flooding, mostly the low molecular weight compounds. Thus, these aromatic parameters should be applied with caution after such methods. The distribution of basic and acidic polar compounds can also be modified affecting the geochemical interpretation. In the case of the basic ones, the biosurfactant greatly influenced the N class species with favorable loss of lower aromaticity compounds. In addition to water solubilization, the compositional changes described in this study can be related to fractionation due to adsorption on reservoir rocks.

Assessing raw materials as potential adsorbents to remove acidic compounds from Brazilian crude oils by ESI (-) FT-ICR MS.

The presence of acidic compounds as naphthenic acids in crude oil causes several problems for the petroleum industry, including corrosion in both upstream and downstream production processes. Based on this scenario, the main objective of this work was to investigate the removal of the acidic compound from two Brazilian heavy oils by adsorption processes using six potential adsorbents: powdered shale, activated carbon, bentonite, silica gel, powdered sandstone and powdered wood. These raw materials were previously characterized by conventional and surface analysis techniques, which show that they offer a good surface area and thermal stability. To evaluate the removal efficiency at the molecular level, the crude oil samples and the filtered oils were analyzed by negative electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry [ESI (-) FTICR MS]. The O2 class, which is related to the relatively high acidity of the samples, was the most abundant in both crude oil samples, moreover, this class was more retained by adsorbents. Silica gel, activated carbon and bentonite were the best adsorbents of acidic compounds from the tested oils, in agreement with their markedly higher surface area and porous volume. Additionally, a chromatographic analysis was performed and showed no changes in the oil profile.

Study of barium sulfate dissolution by scale dissolver based on solutions of DTPA.

In offshore oil wells it is very common to perform seawater injection through injection wells for hydrocarbon recovery. When seawater, rich in sulfate ion, mixes with formation water, whose composition can contain divalent cations such as barium and calcium, it often leads to sulfate salts formation due to their chemical incompatibility. These salts can cause serious damage in production wells. The barium sulfate (BaSO4) is the most problematic scale and may cause many complications. In order to solve this issue, polycarboxylic acids, such as diethylene triamine pentaacetic acid, are used. Thus, the primary focus of this work was to develop an experimental procedure to study the BaSO4 dissolution. Initially, through static tests to understand the relationship between dissolver concentration, temperature and dissolution time, and then through dynamic tests in sandstone reservoirs. Based on the results obtained, in the static tests the best condition for barite to dissolve was at high temperatures (80 ºC) and contact time of 48 hours, since from 50 °C there is an increase in dissolution rate, associated with a long contact time between dissolver and barite. In the dynamic tests, after scale formation, barite could be removed, but the high DTPA concentration should be avoided.