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Adsorption of polar organic components onto sandstone rock minerals and its effect on wettability and EOR potential by Smart Water Aleksandr Mamonov, Ove Andre Kvandal, Skule Strand, and Tina Puntervold Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b00101 • Publication Date (Web): 03 Jun 2019 Downloaded from http://pubs.acs.org on June 6, 2019
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Adsorption of polar organic components onto sandstone rock minerals and its effect on wettability and EOR potential by Smart Water Aleksandr Mamonov, Ove A. Kvandal, Skule Strand and Tina Puntervold University of Stavanger, Norway
Abstract It is generally accepted that reservoir wettability is one of the most important parameters in oil recovery processes. In the published literature, it is believed that the state of reservoir wettability mainly depends on the adsorption or precipitation of oxygen and nitrogen compounds present in the heavy-end fractions of crude oil. However, the establishment of reservoir wetting is a more complex process that involves chemical interactions between all phases of the reservoir: rock mineral surfaces, formation water and surface-active components in the crude oil. In this study, dynamic adsorption tests were performed by flooding modified crude oils with a low asphaltene content through outcrop sandstone cores. Adsorption of crude oil components was analysed by comparing base number (BN) and acid number (AN) of the effluent oil samples with the known initial BN and AN of the crude oil. The experimental results showed that crude oil bases are more active than acids toward the silicate rock mineral surfaces. Within the pore volumes (PV) flooded, it was not possible to achieve equilibrium BN-values due to a continuous adsorption of basic
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components. Spontaneous imbibition tests showed that the core sample behaved slightly waterwet after crude oil flooding. Ion-modified Smart Water as an imbibition fluid in tertiary mode has previously shown potential for wettability alteration and improved oil recovery. With an increase in the amount of injected crude oil through the core, a decrease in oil recovery and a decrease in Smart Water EOR potential were observed. SI oil recovery results indicate reduced positive capillary forces and a change in wetting toward a less water-wet state. Thus, the chemical composition of crude oil should be considered as important parameter for a reliable estimation of the reservoir wettability state and EOR potential by Smart Water injection.
Introduction The focus on Enhanced Oil Recovery (EOR) technologies is growing every year. Modern EOR methods are mostly based on physical and/or chemical processes observed during reservoir development. Sedimentary reservoir rocks can be described as clusters of capillary channels and cracks of various shapes. One cubic meter of reservoir rock contains thousands of square meters of mineral surfaces that come in contact with a small amount of reservoir fluids. Therefore, the distribution of fluids in porous media and the efficiency of oil displacement largely depend on the properties of the contacting phases and reactions at phase boundaries, i.e. Crude oil-Brine-Rock (CoBR) interactions. CoBR interactions determine a number of surface/interface phenomena, such as interfacial tension (IFT), adsorption, wettability, and capillary forces. Surface/interface phenomena play a decisive role in reservoir fluid flow processes. Thus, increasing the efficiency of oil production and EOR cannot be solved without a detailed study and understanding of the CoBR interactions. Crude oils mostly consist of paraffinic, naphthenic, and aromatic hydrocarbons, as well as heteroatom compounds with various functional groups containing oxygen (O), nitrogen (N) and
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sulphur (S). Charged polar components of crude oil, which are acidic and basic in nature, can be adsorbed on the active adsorption centres of mineral surfaces.1 The intensity of the adsorption processes depends on the chemical composition of the crude oil, the ionic composition of the formation water (FW) and the mineral composition of the reservoir rocks.2 The adsorption of crude oil components at the interface between mineral and liquid phases determines the reservoir wettability, which is also influenced by other factors, such as FW composition/salinity/pH, rock mineralogy, temperature etc. Nitrogen (N) and oxygen (O) content increases with increasing resin and asphaltene content in the crude oil. Published literature ascribe the wettability of reservoir rocks to the presence of asphaltenes and their interactions with rock minerals by precipitation or adsorption from the crude oil phase.3,4 Precipitated asphaltene molecules form a layer on the pore walls, which is hardly removed from mineral surfaces, making the rock wetting with crude oil irreversible.5 Nevertheless, a number of studies have confirmed that the wettability of rock minerals can be changed and reproduced in core flooding experiments.6-8 The ability to change and recreate rock wetting conditions can be related to the adsorption and desorption of acidic and basic polar organic components (POC) in crude oils with a lower molecular weight than resins and asphaltenes.1 In other published work, it is also argued that the components of crude oil involved in rock wetting processes are not only present in the asphaltene fraction.9,10 It was also noted that the wetting behaviour of crude oil should correlate with the presence of polar acidic and basic components, that is, the acid number (AN) and the base number (BN) of crude oils.11,12 Previously published adsorption studies on chalk have confirmed that the wettability of the rock can be changed by adsorbing acidic and basic POC from crude oils with asphaltenic content below 1 wt%.13-18 The main conclusion from these studies was that the negatively charged carboxylates,
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i.e. dissociated carboxylic acids RCOO-, adsorb onto positively charged carbonate rock surfaces, thus greatly affecting the wettability. The adsorption process takes place immediately when the oil is in contact with the porous medium, with the highest rate of adsorption during the first pore volumes (PV) of the injected crude oil. With an increased amount of crude oil flooded, the rock wettability shifted toward a less water-wet state, which was confirmed by subsequent spontaneous imbibition (SI) tests. In addition, a comparative analysis of the adsorption of acidic and basic POC confirmed that the adsorption of acidic components was more pronounced. Static adsorption studies by Madsen & Fabricius (1998)19 confirmed that the acidic components of crude oil, represented by long-chain fatty carboxylic acids, have a high affinity for adsorption on calcite surfaces from the oil phase. SI oil recovery tests have also shown that crude oil acids have larger wettability effects than bases in the carbonate core material, demonstrating the importance of AN over BN.20 Unlike positively charged carbonate minerals, sandstone reservoirs are mainly composed of various silicate minerals, which are normally negatively charged in the actual reservoir pH range: 5-9.21 The point of zero charge for silicates is at ~ pH 2-3, meaning that the silicates are negatively charged above this pH value and positively charged below.22 Thereby, positively charged basic POC are more likely to be adsorbed onto sandstone minerals. Previously published adsorption studies by Reed (1968)23 showed that nitrogenous bases were retained on clay-containing reservoir sandstones after crude oil flooding. Other studies have confirmed the high affinity of the basic crude oil components for adsorption on silicate minerals using quinoline (C9H7N) as a model basic component in static adsorption experiments.8,24-27 The main observation from the static tests is that the adsorption processes are largely dependent on the pH of the surrounding water phase. Acidic pH conditions promote the adsorption of protonated quinoline molecules (C9H7NH+) onto
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negatively charged silicate minerals with maximum adsorption at pH≈pKa≈5. Oppositely, increasing pH towards alkaline environment promoted a decrease in adsorption, which can be explained by a decrease in the concentration of protonated basic molecules, and an increase in the neutrally charged basic species. The basic material in crude oils is present in the form of nitrogen-containing aromatic molecules, R3N:, and the acidic material is mainly represented by the carboxylic group, –COOH. Both basic and acidic materials are polar components, and therefore an excess concentration of these components is present at the oil-water interface and can undergo acid-base reactions, i.e. accept or release protons, H+, as pH changes, see Eq. 1 and 2. Thereby, basic and acidic POC can adsorb on negatively charged clay minerals, and it is the protonated species, R-COOH and R3NH+, that have the highest affinity for silicate mineral surfaces.21 In addition, static adsorption studies confirmed that the initially adsorbed POC can be desorbed when the pH of the water phase is alkaline.8,19,26 Basic material
𝑅3𝑁: + 𝐻2O ⇄ 𝑹𝟑𝑵𝑯 + + 𝑂𝐻 ―
(1)
Acidic material
𝑹 ― 𝑪𝑶𝑶𝑯 + 𝐻2O ⇄ 𝑅𝐶𝑂𝑂 ― + 𝐻3𝑂 +
(2)
It has also been experimentally proven that the adsorption and desorption of POC can be affected by the ion composition of water in water-based EOR processes.6 At initial conditions with a low initial formation water saturation and before waterflooding, the amount of adsorbed POC to the rock minerals determines the degree of initial oil/water wetness.14,8,29 In both carbonate and sandstone core systems, it was observed that the subsequent injection of ion-modified “Smart Water” can shift the reservoir wetting toward a more water-wet state, which in turn can result in improved microscopic sweep and an increase in oil recovery.30,31 Austad et al. (2010)30 associated the EOR effect with desorption of the initially adsorbed POC when the formation water (FW) was displaced by Smart Water. A successful Smart Water EOR experiment for sandstone cores is
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presented in Figure 1. A significant increase in oil recovery is observed when the injected brine switches from FW (100 000 ppm) to low salinity (LS) Smart Water brine (1000 ppm). A change in the injected brine also leads to a gradual increase in produced water pH and the establishment of alkaline conditions. The bulk pH of both FW and LS brines is close to pH 6, therefore the observed increase in pH is the result of CoBR interactions.
Figure 1. Tertiary LS Smart Water EOR experiment performed on core B15-R2.8 The core was successively flooded with FW – LS brine at 40 °C. The potential of EOR by Smart Water largely depends on the initial wetting, i.e. the amount and type of adsorbed POC. Thus, the scope of this work is to study the ability of polar organic acidic and basic components to adsorb on silicate mineral surfaces and change wetting in sandstone cores. The adsorption of POC was determined by flooding crude oils with comparable amounts of acidic and basic components through sandstone cores at constant Swi, and comparing the effluent AN and BN with the influent values. The cores were exposed to various total volumes of crude oil (PVs) during dynamic adsorption tests. Finally, the initial core wetting and the potential for wettability alteration by ion-modified Smart Water brine were investigated by SI tests with FW and LS Smart Water as imbibition fluids.
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Experimental section Materials. Experimental work was performed on a sandstone outcrop system, which previously showed good experimental reproducibility. The same core material responded positively to Smart Water EOR in both the secondary and tertiary oil recovery modes.8,32 Crude oil mixtures containing natural POC were used in adsorption and wetting studies. The brines used in the experiments had chemical compositions typical for reservoirs and Smart Water injection. Core material. The outcrop sandstone core B15 used in the experiments was provided by TOTAL E&P. The core material contained ~10wt% of clay minerals (mostly illite) and ~30wt% of feldspar minerals (mostly albite). The mineralogical composition was obtained by X-ray diffraction (XRD) analysis on a rock sample neighbouring the B15 core and is shown in Table 1. All the physical properties of the core, measured during the experiments, are given in Table 2. Table 1. Mineralogical composition of the core material. Mineral composition (wt%) Core
B15
Quartz
Albite
Illite
Chlorite
Calcite
Other
Sum
56.7
31.9
8.4
1.9
0.3
0.8
100
Table 2. Physical properties measured on core B15.
Core
Weight (g)
Diameter (cm)
Length (cm)
PV (ml)
Porosity (%)
BET (m2/g)
Permeability, mD
B15
165.30
3.79
7.04
15.6
19.6
~ 1.8
50 - 100
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Crude oils. The crude oils used in the adsorption tests, M1 and M2, were made by mixing 3 different crude oils with a low asphaltene content and known acid number (AN) and base number (BN). The selected mixing ratio resulted in AN and BN values close to 0.2 mg KOH/g; values that are high enough to minimize analytical uncertainties, and low enough to observe surface interactions/adsorption during core flooding. The mixtures were filtered through a 5 µm filter. No asphaltene precipitation was observed during storage. For each experiment, freshly mixed crude oil, M1 and M2, was prepared with the resulting AN and BN values shown in Table 3. Table 3. Physical and chemical properties of mixed crude oils. Density at 20°C (g/cm3)
Asphaltene content (wt%)
AN
M1
0.800
