Article Cite This: Energy Fuels XXXX, XXX, XXX−XXX
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Adsorption of Polar Organic Components onto Sandstone Rock Minerals and Its Effect on Wettability and Enhanced Oil Recovery Potential by Smart Water Aleksandr Mamonov,* Ove A. Kvandal, Skule Strand, and Tina Puntervold
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University of Stavanger, 4036 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 analyzed 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 flooded, it was not possible to achieve equilibrium BN values because of the continuous adsorption of basic components. Spontaneous imbibition (SI) tests showed that the core sample behaved slightly water-wet 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-enhanced oil recovery (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 an important parameter for a reliable estimation of the reservoir wettability state and EOR potential by smart water injection.
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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, that is, crude oil−brine−rock (CoBR) interactions. CoBR interactions determine a number of surface/ interface phenomena, such as interfacial tension, 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 sulfur (S). Charged polar components of crude oil, which are acidic and basic in nature, can be adsorbed on the active adsorption centers 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 © XXXX American Chemical Society
mineral and liquid phases determines the reservoir wettability, which is also influenced by other factors, such as FW composition/salinity/pH, rock mineralogy, temperature, and so forth. Nitrogen (N) and oxygen (O) content increases with increasing resin and asphaltene content in the crude oil. A published literature ascribes 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 (POCs) 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 behavior 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 Received: January 9, 2019 Revised: May 15, 2019 Published: June 3, 2019 A
DOI: 10.1021/acs.energyfuels.9b00101 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels Previously published adsorption studies on chalk have confirmed that the wettability of the rock can be changed by adsorbing acidic and basic POCs from crude oils with asphaltenic content below 1 wt %.13−18 The main conclusion from these studies was that the negatively charged carboxylates, that is, 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 (PVs) 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 POCs confirmed that the adsorption of acidic components was more pronounced. Static adsorption studies by Madsen & Fabricius19 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 POCs are more likely to be adsorbed onto sandstone minerals. Previously published adsorption studies by Reed23 showed that nitrogenous bases were retained on claycontaining 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 negatively charged silicate minerals with maximum adsorption at pH ≈ pKa ≈ 5. Oppositely, increasing pH toward 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; therefore, an excess concentration of these components is present at the oil−water interface and can undergo acid−base reactions, that is, accept or release protons, H+, as pH changes, see eqs 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 Acidic material
R3N :+ H 2O V R 3NH+ + OH−
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 FW saturation and before waterflooding, the amount of adsorbed POC to the rock minerals determines the degree of initial oil−water wetness.8,14,28,29 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.30 associated the EOR effect with the desorption of the initially adsorbed POC when the FW was displaced by smart water. A successful smart water EOR experiment for sandstone cores is presented in Figure 1. A
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.
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. The potential of EOR by smart water injection largely depends on the initial wetting, that is, 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 POCs were used in adsorption and wetting studies. The brines used in the experiments had chemical compositions typical for reservoirs and smart water injection.
(1)
R−COOH + H 2O V RCOO− + H3O+ (2) B
DOI: 10.1021/acs.energyfuels.9b00101 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels Core Material. The outcrop sandstone core B15 used in the experiments was provided by Total E&P. The core material contained ∼10 wt % of clay minerals (mostly illite) and ∼30 wt % of feldspar minerals (mostly albite). The mineralogical composition was obtained by X-ray diffraction analysis on a rock sample neighboring the B15 core and is shown in Table 1. All of the physical properties of the core, measured during the experiments, are given in Table 2.
placed in an Amott imbibition cell and spontaneously imbibed with FW at 50−60 °C. The cumulative amount of capillary-driven oil production was registered with time. After the oil recovery plateau was reached, the imbibing brine was changed to LS brine (Table 4) to investigate the potential of ion-modified LS smart water to induce wettability alteration and improve the oil recovery. Chemical Analysis of POC in Crude Oil Samples. The AN and BN of the crude oil samples were measured by potentiometric titration using a Mettler Toledo T50 auto-titrator. The methods used were developed by Fan and Buckley34 and are modified versions of the standard methods ASTM D664 for AN titration and ASTM D2896 for BN titration. The reproducibility of the titration methods was confirmed by a minimum 3 parallel tests with absolute errors of ±0.01 mg KOH/g in the AN and BN analyses.
Table 1. Mineralogical Composition of the Core Material mineral composition (wt %) core
quartz
albite
illite
chlorite
calcite
other
sum
B15
56.7
31.9
8.4
1.9
0.3
0.8
100
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RESULTS AND DISCUSSION Laboratory studies of oil recovery processes include core restorations. Initial water saturation should be set to reproduce reservoir conditions and, usually, is carried out by flooding cores with crude oil to the irreducible water saturation. At the same time, upon contact between formation fluids and pore surface minerals, the wettability can change. Wherein, the chemical composition of crude oil and FW, as well as the amount of injected oil, is usually not given sufficient attention. In this paper, the influence of the above factors on the initial wettability and smart water EOR potential in sandstones was considered. In particular, the affinity of crude oil acidic and basic POCs toward pore surface minerals in sandstone cores was investigated, and how the amount of injected crude oil can affect the core wettability. Adsorption of Polar Organic Acids and Bases and Its Effect on Core Wettability. The individual chemical properties of crude oil, brine, and rock phases are complex because of large variation in species in each phase. In a reservoir system, when all three phases interact, the complexity increases even more. Before oil migration into the reservoir, porous rock systems are considered initially water-wet. In the process of oil migration, FW is displaced from the pores because of buoyancy forces and surface-active organic components can adsorb on mineral surfaces. The resulting rock wetting state is dependent on the initial conditions established by CoBR interactions and temperature. Similar processes are reproduced in the laboratory during core restorations. In the process of establishing Swi for a core sample, ion exchanges at the mineral−liquid interface can affect the pH of the FW brine. The charge and, thereby, reactivity of the surface-active components of the crude oil, especially POC, depend on pH as can be seen for the basic components in eq 1 and the acidic components in eq 2. More acidic environment promotes the formation of protonated POCs, which have higher affinities toward negatively charged sandstone minerals. Therefore, it is important to evaluate the equilibrium pH between the FW and the pore surface minerals before core restorations. Figure 2 shows the effluent pH during FW flooding of core B15. The ion composition and salinity of FW were chosen to secure acidic conditions during the core restoration. The pH screening shows that the effluent FW pH stabilized close to ∼7 within 1.5 PV injected. In addition, for the same sandstone core system, a decrease in pH by 0.5−1 units was previously observed with the
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 AN and 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. Brines. Synthetic brines were prepared in the laboratory and used in the experiments; FW brine was used to establish initial water saturation (Swi) in the core prior to the crude oil flooding tests, and FW and LS brines were used in SI oil recovery tests. The ionic composition and brine salinities are shown in Table 4. Methods. Core Pre-treatments. The outcrop sandstone core B15 was previously used in 2 oil recovery tests and needed pre-treatment before any experiments. Mild cleaning was performed on the core at ambient temperature, first by flooding kerosene to remove residual crude oil, and then by flooding heptane to displace kerosene. At the end, the core was flooded with 1000 ppm NaCl brine to remove any remaining salts and dried to constant weight at 90 °C. Brine−Rock Interactions. The mildly cleaned and dried core was 100% saturated and flooded with FW (Table 4) at 50 °C to evaluate chemical interactions between pore surface minerals and ions in the FW brine. Effluent brine samples were collected, and pH values were measured. Core Restorations. The mildly cleaned and dried core was restored prior to the core flooding experiments with crude oil. Initial Water Saturation. Swi with FW was established using the desiccator technique described by Springer et al.33 The core was saturated with five times diluted FW, and then a Swi of ∼20% was established by evaporation. The dilution rate was selected to obtain the original FW composition after evaporation. Crude Oil Saturation and Adsorption of POC. The core sample with a Swi of ∼20% was mounted in a temperature-controlled Hassler core holder with a confining pressure of 20 bar and a backpressure of 10 bar. After temperature stabilized at 50 °C, the core was exposed to crude oil to establish oil saturation. Then, the core was flooded with modified crude oils with predetermined AN and BN values (Table 3) at a rate of 0.1 mL/min. Effluent oil samples were collected in airtight sample glasses using a fraction collector. The AN and BN of the eluted crude oils were determined as a function of PV crude oil injected. The amount of adsorbed polar organic bases was calculated as the difference between the BN of the effluent oil samples relative to the influent crude oil BN. The same procedure was used for calculating the adsorption of polar organic acids. Oil Recovery Tests by SI. Oil recovery tests were performed on the oil-saturated and flooded core without additional aging. The core was
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
C
DOI: 10.1021/acs.energyfuels.9b00101 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels Table 3. Physical and Chemical Properties of Mixed Crude Oils crude oil
density at 20 °C(g/cm3)
asphaltene content (wt %)
AN (mg KOH/g)
BN (mg KOH/g)
absolute error (mg KOH/g)
M1 M2
0.800 0.800
