Influence of Sandstone Mineralogy on the Adsorption of Polar Crude Oil Components and Its Effect on Wettability

The crude oil–brine–rock (COBR) system is a combination of contacting phases where polar organic molecules in crude oil, inorganic ions from the brine phase, and charged mineral surfaces participate in complex interactions. One of the surface phenomena that occur in the COBR system is the adsorption of polar crude oil components, which can directly affect the capillary forces and wettability of the rock. The purpose of this research work was to determine polar organic component (POC) adsorption trends for sandstones of different origins and mineralogical compositions. Adsorption preferences for acidic and basic POCs were quantified by potentiometric titration during dynamic core flooding tests using modified crude oil. The influence of POC adsorption on wettability was investigated by evaluating capillary forces during the displacement of oil in a spontaneous imbibition (SI) process. The results of this work showed a clear relationship between the intensity of POC adsorption and sandstone mineralogy. Greater adsorption capacity and a predominant affinity for bases compared to that for acids were found in the sandstone material containing a sufficient amount of reactive illite clay minerals. On the other hand, the sandstone material consisting mainly of quartz with an insignificant content of kaolinite clay did not show a pronounced tendency to adsorb POCs. All the studied rock materials have also shown a significant impact of POC adsorption on capillary forces and wettability, confirmed during SI tests. As a result, a detailed mineralogical analysis along with crude oil chemistry is required to properly evaluate sandstone wettability and competently plan core flooding laboratory studies.publishedVersio

Reproducing wettability in sandstone reservoir core material in laboratory core restorations

Replicating initial reservoir wettability conditions in core restoration by core cleaning and fluid restoration in the laboratory is of great importance. There are several core cleaning and restoration protocols used in the oil industry and academia that include the usage of different equipment, techniques, and materials. Strong solvents used in core cleaning can remove material that is part of the rock phase leading to more water–wet behavior. Large volumes of crude oil exposure in core restorations can result in high adsorption of polar organic components onto the mineral surfaces giving less water–wet behavior. Therefore, sufficient core cleaning should be targeted, involving no physical damage to the solid rock phase and effective crude oil exposure securing realistic water saturations, avoiding overexposure of crude oil. The objective of this study was to establish an optimum core restoration process in terms of cleaning solvents and the amount of crude oil exposure, to re-establish the same core wettability from one core restoration to the next. Seven sandstone cores from a reservoir on the Norwegian Continental Shelf underwent a series of core restorations. Two different core cleaning procedures were used, in which mild (kerosene/heptane) and strong (toluene/methanol) solvents were involved, and furthermore, the cores were exposed to various volumes of crude oil. Spontaneous imbibition experiments showed that mild core cleaning in combination with 5 pore volumes or more crude oil exposure rendered the cores less water-wet in successive core restorations. More rigorous cleaning with 5 pore volumes of crude oil exposure rendered the cores more water-wet in successive core restorations. From spontaneous imbibition results it was concluded that an optimum core restoration procedure involving mild cleaning and only 1 pore volume of crude oil exposure successfully reproduced core wettability in successive experiments.publishedVersio

Polysulphate: A New Enhanced Oil Recovery Additive to Maximize the Oil Recovery From Carbonate Reservoirs at High Temperature

Seawater (SW) injection is an enhanced oil recovery (EOR) success in the North Sea carbonate reservoirs due to wettability alteration toward a more water-wet state. This process is triggered by the difference in composition between injection and formation water (FW). “Smartwater” with optimized ionic composition can easily be made under laboratory conditions to improve oil recovery beyond that of SW. However, in the field, its preparation may require specific water treatment processes, e.g., desalination, nanofiltration, or addition of specific salts. In this work, a naturally occurring salt called Polysulphate (PS) is investigated as an additive to produce smartwater. Outcrop chalk from Stevns Klint (SK), consisting of 98% biogenic CaCO3, was used to investigate the potential and efficiency of the PS brines to alter wettability in chalk. The solubility of PS in SW and deionized water, and brine stability at high temperatures were measured. Energy dispersive X-ray and ion chromatography were used to determine the composition of the PS salt and EOR solutions, and to evaluate the sulphate adsorption on the chalk surface, a catalyst for the wettability alteration process. Spontaneous imbibition (SI), for evaluating wettability alteration of PS brines into mixed-wet chalk was performed at 90 and 110°C and compared against the recovery performance of FW and SW. The solubility tests showed that the salt was easily soluble in both deionized water and SW with less than 5% solid residue. The deionized PS brine contained sulphate and calcium ion concentrations of 31.5 and 15.2 mM, respectively, and total salinity was 4.9 g/L. This brine composition is very promising for triggering wettability alteration in chalk. The SW PS brine contained 29.6 mM calcium ions and 55.9 mM sulphate ions, and a total salinity of 38.1 g/L. Compared with ordinary SW, this brine has the potential for improved wettability alteration in chalk due to increased sulphate content. Ion chromatography revealed that the sulphate adsorbed when PS brines were flooded through the core, which is an indication that wettability alteration can take place during brine injection. The reactivity was also enhanced by increasing the temperature from 25 to 90°C. Finally, the oil recovery tests by SI showed that PS brines were capable of inducing wettability alteration, improving oil recovery beyond that obtained by FW imbibition. The difference in oil recovery between ordinary SW and SW PS imbibition was smaller due to the already favorable composition of SW. PS brines showed a significant potential for wettability alteration in carbonates and are validated as a potential EOR additive for easy and on-site preparation of smartwater brines for carbonate oil reservoirs. PS salt, added to the EOR solution, provides the essential ions for the wettability alteration process, but further optimization is needed to characterize the optimal mixing ratios, ion compositions, and temperature ranges at which EOR effects can be achieved.publishedVersio

Core wettability reproduction: A new solvent cleaning and core restoration strategy for chalk cores

Laboratory core restoration procedures include different core cleaning solvents, establishment of initial water saturation (Swi) by diverse techniques and processes of crude oil exposure that influence the final core wetting properties.In carbonate reservoirs, the acidic Polar Organic Components (POC) in crude oil are the main components dictating the wettability of the carbonate surface. Negatively charged carboxylates strongly attach to the positively charged CaCO3 surface, thus acting as anchor molecules for the oil phase.During core cleaning with organic solvents, some of the adsorbed POC will be detached from the mineral surfaces, thereby changing the wetting conditions. However, cores are not expected to become completely water-wet even when using strong solvents.The main aim of this paper is to develop core cleaning and core restoration procedures to reproduce initial core wettability.Fractional-wet outcrop chalk cores were exposed to two different core cleaning procedures, (1) mild kerosene-heptane cleaning, or (2) standard toluene-methanol cleaning. Chromatographic wettability tests showed that both cleaning methods increased the fraction of water-wet surface area to a similar extent, but neither of them removed all adsorbed POC from the rock surface. Wettability tests by spontaneous imbibition showed that the kerosene-heptane cleaned core behaved slightly water-wet, while the toluene-methanol cleaned core behaved very water-wet, even though the cores had similar fractions of water-wet surface areas. Increased amount of crude oil exposure during core restoration reduced the water wetness below the initial fractional core wetting.Initial core wettability was successfully reproduced by combining mild cleaning solvents preserving initial adsorbed POC, and minimizing the amount of crude oil exposure during core restoration. Only a 1.5–3.6 %OOIP variation in ultimate recovery during spontaneous imbibition in four different core systems was observed.publishedVersio

Water-based enhanced oil recovery (EOR) by “Smart Water”: optimal ionic composition for EOR in carbonates

Reprinted (adapted) with permission from Fathi, S J., Austad, T., Strand S. (2011) Water-Based Enhanced Oil Recovery (EOR) by “Smart Water”: Optimal Ionic Composition for EOR in Carbonates. Energy & Fuels 25(11), pp. 5173–5179. Copyright (2011) American Chemical Society. The article forms part of the Jafar Fathi's PhD thesis : Fathi, J. (2011) Water-Based Enhanced Oil Recovery (EOR) by "Smart Water" in Carbonate Reservoirs. University of Stavanger.The composition of the injecting brine has a profound effect on the efficiency of water-based enhanced oil recovery (EOR) methods. Recently, we observed that not only is the concentration of the active ions Ca2+, Mg2+, and SO4 2 important for wettability alteration in carbonates but also the amount of non-active salt, NaCl, has an impact on the oil recovery process. Removing NaCl from the synthetic seawater improved the oil recovery by about 10% of original oil in place (OOIP) compared to ordinary seawater. The results were discussed in terms of electrical double-layer effects. In this work, we have modified the seawater depleted in NaCl by adjusting the concentration of active ions, Ca2+ and SO4 2 . Oil displacement studies in outcrop chalk samples by spontaneous imbibition were performed at temperature ranges of 70 120 C using different oils and imbibing fluids. When the concentration of SO4 2 in the seawater depleted in NaCl was increased 4 times, the ultimate oil recovery increased by about 5 18% ofOOIP compared to the seawater depleted in NaCl. The amount of Ca2+ in the seawater depleted in NaCl had no significant effect on the oil recovery at 100 C, but significant improvements were observed at 120 C. Chromatographic wettability analysis confirmed that the water-wet area of the rock surface increased as the oil recovery increased, emphasizing the importance of the ionic composition and the ion concentration of the injecting brine in the water-based EOR methods

“Smart water” as a wettability modifier in chalk: The effect of salinity and ionic composition

"Reprinted (adapted) with permission from Fathi, S J., Austad, T., Strand S. (2010) “Smart water” as a wettability modifier in chalk: The effect of salinity and ionic composition. Energy & Fuels 24(4), pp. 2514–2519. Copyright 2010 American Chemical Society. The article forms part of Jafar Fathi's PhD thesis: Water-based enhanced oil recovery (EOR) in carbonate reservoirs : initial wetting condition and wettability alteration by "Smart Water", Stavanger : University of StavangerSeawater can improve the water wetness of chalk at high temperatures, which improves the oil displacement by spontaneous imbibition of water. It is experimentally verified that the interaction between Ca2+, Mg2+, and SO42− at the chalk surface will displace adsorbed carboxylic acids and increase the water wetness. In this work, the effect of salinity and ionic composition of smart water on oil recovery was studied at different temperatures, 100, 110, and 120 °C. The ultimate oil recovery was compared using seawater as the base fluid. When NaCl was removed from seawater, both the imbibition rate and oil recovery increased in comparison to seawater at the temperatures tested. At 110 and 120 °C, the oil recovery from seawater depleted in NaCl increased by about 10% of original oil in place (OOIP) compared to seawater. A decrease in oil recovery of about 5% of OOIP was observed when increasing the amount of NaCl in seawater 4 times. A systematic decrease in oil recovery was observed when using seawater diluted with distilled water as imbibing fluid. Imbibition tests at 110 °C showed that the water-wet fraction increased 29% for seawater depleted in NaCl compared to 11% for ordinary seawater. Diluted seawater to 10 000 ppm did not change wetting conditions at 110 °C. The results confirmed that not only is the concentration of the active ions Ca2+, Mg2+, and SO42− important for wettability alteration to take place but also the amount of non-active salt, such as NaCl, has an impact on the wettability alteration process, which is discussed as a double-layer effect at the chalk surface. No significant improvement in the ultimate oil recovery was observed during forced displacement by modified seawater

The effects of pH, time and temperature on the stability and viscosity of cellulose nanocrystal (CNC) dispersions: implications for use in enhanced oil recovery

This is a post-peer-review, pre-copyedit version of an article published in Cellulose. The final authenticated version is available online at: http://dx.doi.org/10.1007/s10570-013-9871-0.Cellulose nanocrystals (CNC) are currently being investigated as potential additives for enhanced oil recovery (EOR). Presented in this paper is a study investigating the effects of different physical and chemical environments that low concentration CNC dispersions may be subjected to at oil reservoir conditions. Different concentrations of CNC dispersed in de-ionized water and in a 1000 ppm NaCl brine were subjected to variations in pH and temperature, and the results showed that the dispersions remained stable in the pH range expected in oil reservoirs (between 5 and 9). Stable dispersions were also observed when heated to temperatures ranging from 50 to 90 °C. At extended heat aging at 90 and 120 °C for seven days; beginning degradation was observed for both types of CNC dispersions; with viscosity increase and pH decrease as the most important indicators. CNC dispersed in 1000 ppm NaCl brine was generally more heat tolerant than the CNC dispersed in de-ionized water. The increase in viscosity during heat aging can be very interesting for EOR applications. A fluid that increases its viscosity with heat and time will be easier to inject due to a low initial viscosity, and when the viscosity increases in the porous reservoir, the effect can be a stable waterfront and less viscous fingering, which again can lead to increased sweep efficiency and better oil recovery.acceptedVersio

Adsorption of Crude Oil Components onto Carbonate and Sandstone Outcrop Rocks and Its Effect on Wettability

The processes of establishing and altering reservoir wettability are still subjects of discussion due to the complexity of the underlying crude oil–brine–rock interactions. This study was aimed at investigating the interrelationship between acidic and basic crude oil components and wetting tendencies on core samples of various mineralogies. Core flooding tests with light crude oils were performed to determine whether acidic or basic polar organic components (POC) showed the highest surface reactivity, adsorbing more readily onto the rock surfaces. The influence of this adsorption on wettability and capillary forces was then identified by performing spontaneous imbibition tests. The core materials used were a rather pure Stevns Klint outcrop chalk, a silica-containing Aalborg outcrop chalk, and an outcrop sandstone with silica minerals of quartz, clays, and feldspars. The results of this work showed a correlation between core mineralogy and the type of predominantly adsorbing POC. Pure chalk showed preference for organic acid adsorption over base adsorption, while the sandstone showed opposite preference. Because of the presence of negatively charged silica minerals, the silica-containing chalk showed increased affinity toward basic components and reduced affinity toward the acids compared to that observed for pure chalk. Oil recovery tests by spontaneous imbibition showed that for all cores, the adsorption of oil components significantly reduced water wetness. Thus, the types of minerals that make up the rock surface have a profound influence on the adsorption of POC and on the generation of wettability, and this should be kept in mind when using crude oil to restore core material wettability in the laboratory.publishedVersio

Investigation of a new application for cellulose nanocrystals: a study of the enhanced oil recovery potential by use of a green additive

Cellulose nanocrystals (CNC) were investigated for use in a potential new application, enhanced oil recovery. Core flooding experiments were performed on outcrop sandstone cores using CNC particles dispersed in low salinity brine (CNC–LS). Core flooding experiments performed on fully water-saturated cores confirm that a majority of viscosity-generating CNC particles successfully traverse the cores at temperature conditions ranging from 60 to 120 °C. Oil recovery tests performed on crude oil saturated sandstone cores at 60 and 90 °C show that when CNC–LS is applied in tertiary mode, ultimate oil recovery increases. During tertiary CNC–LS injection, CNC particles exacerbate differential pressure fluctuations, a phenomenon attributable to log jamming in pore throats, causing remobilisation of oil trapped within pore space regions. Results from the current work indicate that CNC particles dispersed in low saline brine remain promising for implementation in enhanced oil recovery operations.acceptedVersio