Significance of Capillary Forces during Low-Rate Waterflooding

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Significance of Capillary Forces during Low-Rate Waterflooding Zahra Aghaeifar,* Skule Strand, and Tina Puntervold

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University of Stavanger, 4036 Stavanger, Norway ABSTRACT: During the past decade, several experimental studies have confirmed that Smart Water injection in sandstone reservoirs could significantly improve oil recovery. Most reported enhanced oil recovery effects are described as wettability alteration creating changes in capillary forces improving the displacement efficiency. Spontaneous imbibition (SI) is one of the main recovery mechanisms in porous media, where positive capillary pressure causes brine invasion into fractional and waterwet oil-containing pores. Numerical models for fluid flow in reservoirs are based on Darcy’s law, describing the viscous forces involved, however not accounting for oil displacement by spontaneous imbibition of water. To demonstrate the importance of capillary forces in oil displacement by wettability alteration induced by Smart Water injection, a series of experimental low-rate oil recovery tests were performed. A low flooding rate was chosen to facilitate wettability alteration and allow capillary forces to contribute in the oil production without the influence of high viscous forces. Only one low-permeability and heterogeneous reservoir sandstone core plug was used in all tests. Before each experiment, the core went through optimized cleaning and restoration procedures to reproduce the same initial core wettability, thus minimizing any influences of varying initial wettability. Both viscous flooding (VF) and SI oil recovery experiments were conducted using different injection brines, and oil recovery results using formation water (FW) and modified seawater (mSW) were compared with secondary and tertiary lowsalinity (LS) Smart Water injection. The experimental results confirmed that core wettability and capillary forces have a significant effect on ultimate oil recoveries, both in spontaneous imbibition and viscous flooding experiments. In this particular low-permeability sandstone, the capillary force-driven oil recovery by SI was as high as that from the low-rate VF experiments. The results confirm the importance of capillary forces in oil recovery processes from low-permeable and heterogeneous rock. Additionally, it was observed that LS brine was able to induce wettability alteration toward more water-wet conditions and significantly improve the ultimate oil recovery, compared to FW and mSW brines.

1. INTRODUCTION

workers is based on an assumption of constant core wettability during the experiments. Johannesen and Graue6 did a systematic investigation of residual oil saturations in low-permeable chalk after waterflooding. They varied the core wettability in the entire range from fractional-neutral to very water-wet, and the differential pressure across the core varied from 0 (SI) to 1600 mbar/cm by adjusting the water injection rate. In general their results agreed with the results by Morrow and co-workers. The lowest residual oil saturation was observed at an Amott water index of Iw = 0.4, which corresponds to fractional-slightly water-wet conditions. The Amott water index is determined from eq 1.7

Viscous, capillary, and gravity forces control oil recovery during water injection. At low flow rates or in low permeable reservoir formations, spontaneous imbibition (SI) and capillary forces driven by surface energies and pore geometries mainly control the efficiency of oil transport.1,2 Neutral to slightly water-wet conditions have been stated to be favorable for optimized oil recovery by waterflooding, Figure 1.3−5 At these wetting conditions, the lowest capillary trapping of oil is expected. The statement by Morrow and co-

Iw =

ΔSw,s ΔSw,s + ΔSw,f

(1)

where ΔSw,s = change in water saturation by spontaneous imbibition of water and ΔSw,f = change in water saturation by forced imbibition of water. Iw = 1 corresponds to a very waterwet case, and Iw = 0 corresponds to a fractional-neutral-wet case. What Johannesen and Graue also observed was that as the Iw increased to more water-wet conditions, the difference in oil recovery by viscous flooding (VF) or by SI decreased.6 Thus, when water-wetness increased, capillary forces increased and water was sucked into smaller pores displacing the oil therein. Figure 1. Maximum waterflood oil recovery at neutral to slightly water-wet conditions due to low capillary trapping of oil. OW = oilwet, NW = neutral-wet, and WW = water-wet. Drawn on the basis of results from ref 4. © XXXX American Chemical Society

Received: January 3, 2019 Revised: March 9, 2019

A

DOI: 10.1021/acs.energyfuels.9b00023 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels However, in a waterflooding process, increased water-wetness may also lead to increased oil trapping and bypassing of pores, thereby lowering the ultimate oil recovery at very water-wet conditions, as shown in Figure 1. Especially interesting in the work of Johannesen and Graue6 was the fact that, at the lowest flow rates, with differential pressures < 50 mbar/cm, negligible differences in the residual oil saturations were observed by either SI or VF across the entire wettability range. Therefore, in the main part of the reservoir (away from injection and production wells) experiencing the lowest flow rates, it is hypothesized that the capillary forces and spontaneous imbibition into small pores with high capillary entry pressures are extremely important for the microscopic sweep efficiency during a waterflood. Smart Water is a brine of favorable ionic composition that is able to alter the wettability of pore surface minerals toward more water-wet conditions, hence increasing the capillary forces and the microscopic sweep efficiency. In sandstones, brines of low salinity are generally able to enhance oil recovery, often referred to as low-salinity (LS) injection. Fresh water has been injected into reservoirs for decades to improve oil recovery;8,9 thus the method itself is not novel. However, the reason for it being so successful has been discussed vividly for the past 20 years. Today, most researchers seem to agree that the initial core wettability established during core restoration can be modified toward more water-wet conditions by injecting a brine with a different composition than the formation water (FW).10 According to the chemical Smart Water enhanced oil recovery (EOR) mechanism for sandstone reservoirs proposed by Austad and co-workers,11 acidic and basic polar organic molecules in the crude oil are the main wetting parameters. A crude oil/brine/rock (CoBR) equilibrium influenced by FW composition, salinity, pH, pressure, and temperature has been established in the reservoir over geological time, dictating the initial wettability. Protonated polar components adsorb onto negatively charged sites on the mineral surfaces in competition with inorganic cations from FW, such as Ca2+, Na+, and H+.3,11 When a brine with a different and favorable ion composition and salinity than FW is injected, the established chemical equilibrium is disturbed, inducing a wettability alteration toward more water-wet conditions. Increased positive capillary forces will improve the microscopic sweep efficiency by SI into previously bypassed oil-containing pores of low water wetness, mobilizing a new bank of oil, Figure 2.3

Reservoir simulation models include only viscous and gravitational displacement forces, neglecting capillary forces. However, in three-dimensional heterogeneous pore networks, the preferred pathways for the injection brine are high permeable pores with the least restrictions. Oil displacement from less accessible and low-permeable pores is therefore completely dependent on positive capillary forces and SI. Water injection into reservoirs with a radial flow geometry results in a low laminar flow rate in the main part of the reservoir, away from the injection well and toward the production well. At low flow rates, time-dependent wettability alteration processes can take place within the waterflooding time frame, facilitating water imbibition into smaller pores, thus contributing to the overall oil recovery by improved sweep efficiency. At high differential pressures in the reservoir, i.e., close to the injection and production wells, viscous forces are large and efficient in displacing oil. However, it is hypothesized that at low/negligible viscous forces away from the wells, the capillary forces dominate the oil displacement. In this study, oil recoveries by SI and low-rate VF were compared to investigate the importance of capillary forces in the oil recovery process. A series of oil recovery experiments was performed at high reservoir temperature (Tres > 100 °C) using a single reservoir sandstone core securing the same pore size distribution. Optimized core preparation procedures were used to minimize variations in core wettability established in each core restoration. In addition, the oil recovery and Smart Water EOR potential by using formation water (FW), modified seawater (mSW) or low-salinity water (LS) were compared.

2. EXPERIMENTAL SECTION 2.1. Material. Reservoir Core Material. One preserved reservoir core, C#3, was used in this study. Mineralogical data from a representative rock sample were obtained by QEMSCAN analysis, performed by Rocktype Ltd., U.K., and are presented in Table 1. Note that during core cleaning, dissolution of anhydrite, CaSO4 (s), was detected in water effluent samples, while anhydrite minerals were not detected in the QEMSCAN analysis. Physical core properties, measured during core preparation, are given in Table 2. Brunauer−Emmett−Teller (BET) surface area was measured on a small representative rock sample after cleaning with toluene and methanol. Brines. The reservoir FW has a medium salinity of 63000 ppm, with a Ca2+/Mg2+ ratio of 6.3. A suggested injection brine for this high-temperature reservoir is a modified seawater (mSW) brine, which is treated seawater with reduced concentrations of SO42−, Ca2+, and Mg2+ to decrease scale formation potential. Another suggested injection brine is a LS brine, which is a 20 times diluted mSW brine. The brine compositions and properties are presented in Table 3. Crude Oil. A stabilized reservoir crude oil was used in the oil recovery experiments. The crude oil was centrifuged and filtered through a 5.0 μm Millipore filter to remove any solid particles and water. The acid number (AN) and base number (BN) of the crude oil were determined by potentiometric titration. The methods used were developed by Fan and Buckley, and they are modified versions of ASTM D664 and ASTM D2896.12,13 The asphaltene content was measured based on a modified version of ASTM D6560, also proposed by Buckley. The crude oil viscosity was measured at 20 and 60 °C using a MCR 302 rheometer delivered by Anton Paar. The crude oil properties are given in Table 4. 2.2. Core Preparation. Before and between each oil recovery experiment, the core went through the same preparation procedure, involving mild core cleaning and a following core restoration. Mild Core Cleaning. The core was mildly cleaned in a Hassler core holder at ambient temperature. It was first flooded with low aromatic

Figure 2. Principles of Smart Water EOR effects induced by wettability alteration. Reprinted with permission from ref 3. Copyright 2016 Elsevier. B

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Energy & Fuels Table 1. Mineralogical Data Obtained by QEMSCAN Analysis of the Core Material minerals, wt % quartz

K-feldspar

albite

biotite

muscovite

illite

chlorite

kaolinite

smectite

quartz−clay mix

other clays

other phases

75.0

9.8

4.2

0.04

3.2

0.3

0.4

4.4

0.2

0.1

0.8

1.6

Table 2. Physical Core Properties core

length, cm

diameter, cm

pore volume, mL

C#3

7.03

3.84

11.8

Table 5. Experimental Test Program porosity, % kwro, mD 14.6

a

BET, m2/g

9.0

0.92

core

core restoration

C#3

mild cleaning; kerosene, n-heptane, and 1000 ppm NaCl; Swi = 0.15 FW; 5 PV crude oil

oil recovery experiment C#3-R2, C#3-R3, C#3-R4, C#3-R5, C#3-R6,

kwro: NaCl (1000 ppm) permeability at Sor (heptane) during first restoration (C#3-R1) a

VF with LS VF with mSW-LS SI with FW-LS SI with LS SI with mSW-LS

Table 3. Brines Properties and Ionic Compositions (mmol/ L (mM)) FW, mM

mSW, mM

LS, mM

Na+ K+ Li+ Ca2+ Mg2+ Ba2+ Sr2+ Cl− HCO3− SO42−

ion

929.8 17.8 0.0 44.2 7.0 5.2 3.0 1058.8 7.7 0.0

477.2 8.1 0.0 8.2 13.5 0.0 0.0 527.9 0.3 0.4

23.9 0.4 0.0 0.4 0.7 0.0 0.0 26.4 0.02 0.02

pH TDS, mg/kg density, g/cm3

6.8 63000 1.042

7.0 30725 1.020

6.4 1536 0.999

Figure 3. Core flooding setup for oil recovery tests by viscous flooding: IB = injection brine; O/W = oil/water. The core was successively flooded with different injection brines at a constant rate of 4 PV/day (pore volumes per day). The cumulative oil production was monitored. Produced water (PW) samples were collected and analyzed for ionic composition, pH, and density. Process parameters such as temperature, inlet pressure, and pressure drop over the core were logged. Spontaneous Imbibition Tests. The restored core was placed vertically on marble balls inside a steel HTHP (high-temperature, high-pressure) SI cell, as described in the schematic of the SI setup shown in Figure 4.

kerosene to displace the crude oil phase. At clear effluent, the kerosene was displaced by n-heptane injection. At the end, the core was flooded with 4 pore volumes (PV) with 1000 ppm NaCl brine to remove initial brine and any easily dissolvable salts. The pressure drop was monitored for permeability calculation. Effluent brine samples were collected for chemical analyses. Finally, the core was dried at 60 °C to constant weight. Core Restoration. Initial FW saturation of Swi = 0.15 was established on the mildly cleaned and dried core using the desiccator technique.14 The core was equilibrated in a closed container for 3 days to establish an even ion distribution throughout the core. The core was then mounted in a Hassler core holder, evacuated for 5 min, saturated with crude oil before flooding with crude oil, 2 PV in each direction to secure even oil distribution inside the core. Finally, the core was placed on marble balls in a steel aging cell surrounded by crude oil, and aged for 2 weeks at 10 bar and reservoir temperature (Tres > 100 °C) . 2.3. Oil Recovery Tests. Five oil recovery tests were performed on reservoir core C#3. For comparison purposes, the core went through the same core preparation procedure before each test to reproduce the initial core properties. Two viscous flooding (VF) experiments and three spontaneous imbibition (SI) experiments were performed. The experimental test program is summarized in Table 5. Viscous Flooding Tests. The restored core was placed in a Hassler core holder with a confining pressure of 20 bar and a back-pressure of 10 bar at reservoir temperature (Tres > 100 °C). The experimental setup is visualized in Figure 3.

Figure 4. High-temperature spontaneous imbibition test setup: IB = injection brine.

Table 4. Crude Oil Properties

crude oil

AN, mg of KOH/g

BN, mg of KOH/g

asphaltene, wt %

density at 20 °C, g/cm3

viscosity at 20 °C, mPa s

viscosity at 60 °C, mPa s

0.16

0.76

1.1

0.847

7.0

2.9

C

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Energy & Fuels The SI cell was pressurized to 10 bar with the surrounding imbibing brine, and the temperature was increased to test conditions (>100 °C). The spontaneously produced oil accumulates at the top of the cell, is at given times slowly drained at constant pressure, and sampled into a graduated buret outside the heating chamber. The cumulative volume of oil produced is measured and reported as a percentage of original oil in place (%OOIP) versus time. The imbibing fluid was changed during the experiment by displacing the imbibing brine with a new brine at test temperature. 2.4. Analyses. Ion Analyses. Chemical analyses of the effluent brine samples were performed using Dionex ICS5000+ ion chromatograph (IC). The effluent samples were diluted 1000 times prior to analyses. Ion concentrations were calculated based on the external standard method. Fluid Density. Fluid densities were measured using a density meter DMA-4500 from Anton Paar. Viscosity. A Physica MCR 302 rheometer delivered by Anton Paar were used for viscosity measurements. The measurements were performed with cone and plate geometry at constant shear rates in the range of 10−100 s−1, and at temperatures 20 and 60 °C. BET Surface Area. BET surface area measurements were carried out in a TriStar II PLUS instrument from Metromeritics. The measurements were performed on rock samples taken from the same core material used in this study. pH Measurements. The pH was measured using the Seven Easy pH meter delivered by Mettler Toledo, using a Semimicro pH electrode optimized for small sample volumes. The repeatability of measurements was ±0.02 pH units at ambient test temperature.

Figure 5. Oil recovery by viscous flooding at Tres on core C#3-R2. The core was flooded with LS brine in secondary mode at a rate of 4 PV/day. PW samples were collected and pH monitored.

the significant increase in pH can only be explained by CoBR interactions taking place inside the core. A comparable oil recovery test was performed, C#3-R3, where the core was flooded with mSW in secondary mode followed by LS brine injection in tertiary mode, as seen in Figure 6.

3. RESULTS AND DISCUSSION In this experimental work reservoir material from a hightemperature sandstone reservoir (Tres > 100 °C) have been used. Only one core has been used in all experiments to secure the same pore distribution and heterogeneity throughout all tests. The core had a porosity of 14%, and a permeability of 9 mD, measured as water permeability at residual heptane saturation. A series of oil recovery experiments were performed, including both viscous flooding and spontaneous imbibition experiments, to evaluate the initial core wettability, wettability alteration by mSW and LS brines, and ultimate oil recoveries. The flooding rate during viscous flooding displacement was kept low, 4 PV/day, which corresponds to 0.033 mL/min or approximately 1 ft/day, to allow capillary forces to work, also during the viscous flooding. Due to the low permeability, it is expected that the presence of positive capillary forces at slightly water-wet initial conditions can significantly affect the oil recovery both in a spontaneous imbibition process and in a low-rate viscous flooding process. 3.1. Oil Recovery by Low-Rate Viscous Displacement. Two oil recovery experiments by VF were performed to study the oil recovery potential of LS brine, or a modified seawater brine, which is a natural injection fluid for a high-temperature offshore reservoir. In the first test, LS brine was injected in secondary mode. At low flow rate, positive capillary forces are allowed to contribute in the oil displacement process. The oil recovery result is presented in Figure 5. The oil recovery profile confirmed a piston-like fluid displacement reaching an oil recovery of 60%OOIP after only 0.6 PV injected. The first produced water (PW) sample had a pH of 6.2, confirming initial acidic conditions favorable for initial, mixed core wettability. The PW pH increased from 6.2 to 7.6 during the LS injection, giving an ultimate oil recovery of 63%OOIP. With a bulk pH of the LS brine of 6.4,

Figure 6. Oil recovery test by viscous flooding of core C#3-R3 at Tres. The brine injection sequence was mSW − LS at a rate of 4 PV/day. PW samples were collected and pH monitored.

During secondary mSW injection, only crude oil was produced until water breakthrough at 0.42 PV injected and at 46%OOIP oil recovery. Production of both oil and water continued until 3 PV brine injected, reaching a recovery plateau of 51%OOIP. In the first PW sample, pH was slightly below 6, supporting a mixed core wettability. The pH only slightly increased to 6.4 during the mSW flooding, due to different CoBR interactions taking place inside the core compared to the LS flooding. With a bulk pH of mSW of 7.0, the observations confirm that the PW pH is controlled by CoBR interactions. The divalent cations in the mSW brine prevent a large pH increase by complexing with hydroxyl, OH−, ions generated by ion exchange at the mineral surfaces,11,15,16 as observed previously in a surface reactivity test on the same core material, in the absence of crude oil.17 After 4 PV of mSW was injected, the injection brine was changed to LS brine. At that point, the average water saturation (Sw) in core C#3-R3 was calculated to 57%. A remaining oil saturation of 43%, should be sufficient for observing LS EOR effects in tertiary mode. As observed in Figure 6, more than 1 PV of LS brine was needed before any pH increase was observed. Along with the pH increment, a simultaneous increase in oil recovery was observed. After 3 PV D

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Figure 7. Inlet pressure (P) and pressure drop (ΔP) over the core during the oil recovery test by (a) secondary LS injection in core C#3-R2 and (b) secondary mSW − tertiary LS injection in core C#3-R3. Injection rate was 4 PV/day.

LS brine injection, the PW pH had reached the maximum value of 7.6. The production plateau of 60%OOIP was reached after 4 PV of LS brine was injected. Interestingly, the ultimate oil recovery by LS brine injection was the same in either secondary or tertiary mode. However, by comparing the times of water breakthrough during secondary injection of mSW brine, Figure 6, and LS brine, Figure 5, a large difference was observed. Water breakthrough during mSW injection was observed after an oil recovery of 46%OOIP, while much later, at 58%OOIP, during LS brine injection. The results confirm significant improvement in the displacement efficiency using LS brine. It should be noted that the viscosity of the LS brine is slightly lower than that of mSW brine, which means that the extra oil observed by LS brine is not a result of improved mobility ratio. Inlet pressure (P) and core pressure drop (ΔP) were monitored during both the LS and mSW-LS injection tests presented above, and the data are shown in Figure 7. An overall decline in pressure drop was observed in both core flooding tests, Figure 7a,b, with only minor differences between the LS and mSW floods. This observation suggests that there was no swelling of clays nor fines migration taking place inside the core during LS flooding. In addition, when the flooding fluid was changed from mSW to LS in Figure 7b, there was no observed change in pressure drop. Thus, the extra oil recovered by the tertiary LS flood was concluded to arise from wettability alteration. In both experiments, fluctuations in pressure drop were observed initially. These fluctuations are mainly due to a two-phase flow of oil and brine across the back-pressure valve during the oil production phase. PW density was monitored during the oil recovery test by mSW − LS flooding, C#3-R3, and the measured data are given in Figure 8. More than 1.5 PV LS brine injection was needed to observe a significant decrease in the PW salinity, confirming heterogeneous pore size distribution, which is not favorable for observing a high viscous displacement efficiency. In low permeable heterogeneous porous media, the injection fluid will prefer to move through the larger pores with the largest permeability, thus not sweeping the fluids in the smaller pores. Heterogeneous pore size and mineral distributions were confirmed in the QEMSCAN analysis results measured on a representative rock sample, Figure 9. Here the dark blue color

Figure 8. PW density measured during the oil recovery test on the restored core C#3-R3. The core was successively flooded with mSW − LS brine at a rate of 4 PV/day.

represents the porosity and, therefore, the pore sizes. Assorted sizes and shapes of pores were observed in the core material, confirming heterogeneous rock properties and supporting a potential for improving oil recovery by wettability alteration toward more water-wet conditions, thus improving the microscopic sweep efficiency. In heterogeneous cores, improved displacement efficiency could be explained by increased capillary-driven oil during the low-rate viscous core flooding experiments. 3.2. Oil Recovery by Capillary forces. It has previously been observed that an alkaline environment favors wettability alteration toward more water-wet conditions.18 Increased capillary forces could improve the microscopic sweep efficiency, but could also increase the capillary trapping of oil.19 If, however, remobilized oil by improved sweep efficiency is larger than the increased capillary trapping, a positive EOR effect should be observed. The ability of a LS brine to change wetting properties and increase the capillary forces could be tested by performing oil recovery tests by spontaneous imbibition, in both secondary and tertiary imbibition mode. To evaluate how the individual brines used in the oil recovery tests by viscous flooding affect the core wettability, and how they could contribute to generating positive capillary forces during brine flooding processes, a series of spontaneous E

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Figure 9. QEMSCAN image of mineral and pore size distributions measured on a representative rock sample. The porosity was determined to be 10.8%.

days, confirming a frational and quite water-wet initial core wettability. When the imbibing fluid was changed to LS brine, a gradual increase in the oil recovery was observed, reaching a recovery plateau of 48%OOIP, confirming that the LS brine was capable of generating increased positive capillary forces and improving the oil recovery by spontaneous imbibition. During the oil recovery experiments by viscous flooding, the LS brine was more efficient in secondary mode, Figure 5, than used in tertiary mode, Figure 6. To evaluate the capability for a LS brine to generate increased capillary forces and improve the oil recovery by spontaneous imbibition in secondary mode, a new oil recovery test was performed, C#3-R5. For comparison, both SI results are presented in Figure 11.

imbibition experiments was performed on the restored core C#3, using FW, mSW, and LS as imbibition brines. The viscous flooding experiments confirmed pH increments during LS injection, Figure 5 and Figure 6. After the fourth core restoration, core C#3 was exposed to FW as imbibing fluid. By using FW as imbibing fluid, no chemical induced wettability alteration should take place, and the experiment gives important information about the core wettability and positive capillary forces available within the porous network. The results from the SI test on core C#3-R4 are shown in Figure 10. The fact that the core imbibes FW confirms positive capillary forces and that the core is on the water-wet side; Iw > 0.0. An oil recovery plateau of 42%OOIP was reached after 5

Figure 11. Oil recovery test at Tres by spontaneous imbibition (SI) of LS brine in core C#3-R5 in comparison with SI of FW-LS in core C#3-R4.

Figure 10. Oil recovery test at Tres by spontaneous imbibition (SI) on core C#3-R4, using FW as imbibing brine followed by LS brine. F

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water-wet mineral surface, the process is described elsewhere by Austad and co-workers.3,11,15 FW contains much higher concentrations of Ca2+, Mg2+, and Na+ than does mSW, Table 3, and this will reduce the potential of generating higher pH during the tertiary LS imbibition, due to complexation between the cations and the generated hydroxyl ions, OH−. Previous modeling work has shown that Mg2+ easily binds to OH− and may precipitate Mg(OH)2, and this tendency is increasing with temperature. The same trend was observed with Ca2+, however to a lower extent.11 3.3. Effect of Capillary Forces and Spontaneous Imbibition on the Oil Recovery Process. One lowpermeable reservoir sandstone core has been used in several oil recovery tests by both spontaneous imbibition and low-rate viscous flooding. A low rate was used during brine injection to allow the capillary forces to work, because wettability alteration does require CoBR interactions. Low core flooding rates are also more representative of actual fluid flow in reservoirs. One single core has been used in all experiments to secure the same pore distribution and heterogeneity in all tests, and the same optimized core restoration procedure was used in all core experiments to minimize variations in the initial core wettability between each experiment. In previously published work by Aghaeifar et al.17 viscous flooding experiments were performed on two other reservoir cores from the same well, and all experiments showed that LS brine injection in secondary mode recovered significantly more oil than that with mSW brine injection. This conclusion was independent of the number of restorations the cores had gone through, because when the brine sequences were deliberately switched, the oil recovery by LS injection was still higher than that by mSW injection. Therefore, it is believed that only minor differences in initial wetting conditions exist owed to the number of core restorations. Table 6 summarizes the oil recovery results from both SI and VF experiments completed in this study, using FW, mSW, and LS brines.

The LS brine generated a huge increase in capillary forces compared to FW, and both the rate of imbibition and the ultimate oil recovery of 67%OOIP reached after 6 days confirmed that the LS brine was able to change the core wettability toward more water-wet conditions. Interestingly, the results presented in Figure 11 and Figure 5 showed that secondary LS oil recoveries gave 67%OOIP by SI, while VF only gave 60%OOIP. These results confirm that core wettability and capillary forces within the porous network are extremely important in oil recovery processes from heterogeneous porous systems. The capillary contribution needs to be accounted for when oil recovery potential from reservoirs is discussed. In addition, capillary forces should also be included when mathematical models and reservoir simulation models are developed for reliably describing the recovery mechanisms within porous networks. As FW − LS is not a realistic brine injection sequence in most reservoirs, a final SI test was performed using mSW − LS brine instead on core C#3-R6. All three spontaneous imbibition tests performed are compared in Figure 12.

Figure 12. Oil recovery test at Tres by spontaneous imbibition (SI) on core C#3-R6 using mSW-LS brines, and in comparison with spontaneous imbibition of LS in C#3-R5 and FW-LS in core C#3-R4.

Table 6. Oil Recovery Tests by SI and VF Performed on Core C#3

The spontaneous imbibition results confirm that mSW neither behaves as a Smart Water nor creates increased positive capillary forces compared with FW. The recovery plateau of 38%OOIP reached by imbibing mSW is somewhat lower, but comparable with the 42%OOIP recovery plateau achieved with FW imbibition. Due to uncertainties in the experiments, any further attempt to explain the results, given they are significantly different, will not be attempted at this point. However, when the SI brine was changed from mSW to LS brine, a pronounced increase in the oil recovery up to 68% OOIP was achieved, which is at the same recovery plateau as that observed for LS brine imbibition in secondary mode. Note, however, a slight increase in the time taken to reach the recovery plateau by imbibition of LS in tertiary mode. Observe the significant difference in oil recovery by tertiary LS imbibition after FW and mSW imbibition, up to 48%OOIP and 68%OOIP, respectively. This difference can be explained by wettability alteration potential and comparing the concentrations of divalent ions in FW and mSW. Cation exchanges at mineral surfaces, such as feldspars and clays, are responsible for creating the alkaline environment observed during LS injection.18,20−22 At alkaline conditions the adsorbed polar organic crude oil molecules will desorb, creating a more

test no. C#3-R2 C#3-R3 C#3-R4 C#3-R5 C#3-R6

test type VF SI

brines

secondary oil recovery plateau, %OOIP

LS mSW − LS FW − LS LS mSW − LS

63 51 42 67 38

tertiary LS oil recovery plateau, %OOIP

LS EOR effect, %OOIP

60 48

9 6

68

30

The results confirm that core wettability and positive capillary forces affect the oil recovery in VF processes. The LS brine behaved as a Smart Water and generated significantly increased positive capillary forces. mSW was not able to generate increased capillary forces compared with FW. According to these results, the highest oil recovery was obtained in the most water-wet system. This is in contradiction to the work performed by Morrow and co-workers, redrawn in Figure 1.4,5 However, Jadhunandan and Morrow4 performed their work on rather high-permeable Berea outcrop sandstone cores and at higher injection rates. Figure 1 is maybe not valid for all core systems but limited to Berea sandstone with its specific mineralogy and high permeability. The above interpretation was also suggested by Buckley et al.23 G

DOI: 10.1021/acs.energyfuels.9b00023 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels Instead, the results in this study agree with the observations made by Johannesen and Graue6 in low-permeable chalk, that, at low flow-rates, oil recoveries by spontaneous imbibition or low-rate viscous flooding converged as the water wetness increased. In the present study, the highest oil recoveries, 67− 68%OOIP, were observed in SI experiments using LS Smart Water brine in secondary mode or in tertiary mode after mSW imbibition. These recovery values were significantly higher than those obtained in the viscous flooding experiments with LS brine, reaching 60−63%OOIP. These observations suggest that capillary forces significantly influence oil recovery during low-rate viscous flooding in a heterogeneous and lowpermeable sandstone core and that capillary forces should be considered when developing mathematical models for oil recovery processes. When comparing injection brines, the results showed that LS brine injection in secondary mode was far more efficient than mSW injection after 1 PV was injected, reaching ultimate oil recoveries of 60 and 50%OOIP, respectively. Secondary LS injection generates increased capillary forces, giving a much more stable oil displacement front with an ultimate recovery of 63%OOIP, hardly producing any oil after water breakthrough. When mSW, which generates no extra positive capillary forces compared to FW, is injected in secondary mode, a less stable oil displacement front is achieved, with earlier water breakthrough and a larger transition period with both oil and water production. The ultimate recovery plateau for mSW was 51% OOIP, which is much lower than that by LS brine injection. The extra oil recovery can be explained by a combination of wettability alteration at pore throats increasing the number of pores accessible for the injection brine, increased SI in smaller pores, and redistribution of the oil attached to pore surfaces as visualized in Figure 13. During injection of brines without wettability alteration properties, such as FW, the observed oil recovery is a result of a combination of viscous oil displacement from large pores and high-permeability pathways and wettability-controlled spontaneous imbibition processes mobilizing oil from less accessible pores. When Smart Water is injected, in the same porous network in tertiary mode, it will flow through the same main pathways with the lowest restrictions established by the first injected brine. However, with the ability to induce desorption of polar organic anchor molecules from mineral surfaces, hence inducing positive capillary forces, the oil recovery could increase due to wettability alteration and SI from previously nonaccessible pores. The larger pore pathways will then behave as both a distribution network for the Smart Water and as the transport route for the mobilized oil as illustrated in Figure 13.

Figure 13. Oil distribution and displacement efficiency in a heterogeneous porous network with large, medium and small pores during FW and Smart Water injection. (a) Initial oil saturation in heterogeneous pore systems. (b) Residual oil saturation after FW injection at fractional slightly water-wet conditions where the oil displacement is controlled by viscous and capillary forces, and (c) Residual oil saturation after wettability alteration with Smart Water where the oil displacement is controlled by viscous and stronger capillary forces.

• Secondary LS injection brine showed significantly increased displacement efficiency and the highest ultimate oil recovery. • Heterogeneous pore size distribution was confirmed by both VF experiments and QEMSCAN analysis, which together with low core permeability should favor capillary forces as an important recovery mechanism. • Spontaneous imbibition of FW confirmed that the restored core behaved slightly water-wet. • Spontaneous imbibition of mSW did not improve the wetting conditions compared to FW. • Increased spontaneous imbibition of LS brine in tertiary mode after FW or mSW imbibition confirmed that the LS brine was able to change the core wettability toward more water-wet conditions. • Spontaneous imbibition of LS brine in secondary mode was the most efficient process, giving the highest ultimate oil recovery. It was significantly more efficient in both speed and ultimate recovery, confirming the results observed in viscous flooding experiments. • Increased oil recoveries were observed for more waterwet core systems. • A comparison of the oil recovery results by both low-rate viscous flooding and spontaneous imbibition showed similar oil recovery plateaus, confirming that spontaneous imbibition due to positive capillary forces is a major recovery mechanism in heterogeneous pore systems, and need to be accounted for in simulation models.

4. CONCLUSIONS Spontaneous imbibition and low-rate viscous flooding results have been compared for a reservoir sandstone core at high reservoir temperature (Tres > 100 °C). FW, mSW, and LS brine injection efficiencies on oil recovery in secondary mode have been compared, and the LS Smart Water EOR potential in tertiary mode has been determined for this system. The following conclusions were drawn: • Low-rate viscous flooding experiments confirmed significantly higher ultimate oil recoveries using LS Smart Water compared to mSW flooding, in both secondary and tertiary injection mode. H

DOI: 10.1021/acs.energyfuels.9b00023 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels

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Society of Petroleum Engineers: Richardson, TX, USA, 2006; DOI: 10.2118/99884-MS. (14) Springer, N.; Korsbech, U.; Aage, H. K. Resistivity index measurement without the porous plate: A desaturation technique based on evaporation produces uniform water saturation profiles and more reliable results for tight North Sea chalk. International Symposium of the Society of Core Analysts, Pau, France, Sep. 21−24, 2003; Society of Core Analysts: Rusagonis, NB, Canada, 2003. (15) RezaeiDoust, A.; Puntervold, T.; Austad, T. Chemical Verification of the EOR Mechanism by Using Low Saline/Smart Water in Sandstone. Energy Fuels 2011, 25 (5), 2151−2162. (16) Piñerez Torrijos, I. D.; Austad, T.; Strand, S.; Puntervold, T.; Wrobel, S.; Hamon, G. Linking low salinity EOR effects in sandstone to pH, mineral properties and water composition. SPE Improved Oil Recovery Conference, SPE-179625-MS, Tulsa, OK, USA, Apr. 11−13, 2016; Society of Petroleum Engineers: Richardson, TX, USA, 2016; DOI: 10.2118/179625-MS. (17) Aghaeifar, Z.; Strand, S.; Puntervold, T.; Austad, T.; Sajjad, F. M. Smart Water injection strategies for optimized EOR in a high temperature offshore oil reservoir. J. Pet. Sci. Eng. 2018, 165, 743− 751. (18) Piñerez Torrijos, I. D.; Puntervold, T.; Strand, S.; Austad, T.; Abdullah, H. I.; Olsen, K. Experimental study of the response time of the low-salinity enhanced oil recovery effect during secondary and tertiary low-salinity waterflooding. Energy Fuels 2016, 30 (6), 4733− 4739. (19) Morrow, N. R. Wettability and its effect on oil recovery. SPE21621-PA. JPT, J. Pet. Technol. 1990, 42 (12), 1476−84. (20) Aksulu, H.; Håmsø, D.; Strand, S.; Puntervold, T.; Austad, T. Evaluation of low salinity EOR-effects in sandstone: Effects of temperature and pH gradient. Energy Fuels 2012, 26 (6), 3497−3503. (21) Blum, A. E. Feldspars in weathering. In Feldspars and their reactions; Parsons, I., Ed.; Kluwer Academic: Dordrecht, The Netherlands, 1994; pp 595−630. (22) Chou, L.; Wollast, R. Steady-state kinetics and dissolution mechanisms of albite. Am. J. Sci. 1985, 285 (10), 963−993. (23) Buckley, J. S.; Bousseau, C.; Liu, Y. Wetting Alteration by Brine and Crude Oil: From Contact Angles to Cores. SPE-30765-PA 1996, 1 (03), 341−350.

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. ORCID

Zahra Aghaeifar: 0000-0002-9054-5404 Tina Puntervold: 0000-0002-5944-7275 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS We acknowledge the University of Stavanger for financial support, and the oil company for supplying the reservoir material, for permission of publication, and for financial support of research activities in the Smart Water EOR group at the University of Stavanger. We thank Hossein Ali Akhlaghi, Gadiah Albraji, and Farasdaq Muchibbus Sajjad for their involvement in parts of the laboratory work. Finally we thank Jenny Omma and Aukje Benedictus at Rocktype Ltd., UK for the QEMSCAN analyses and support.

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REFERENCES

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DOI: 10.1021/acs.energyfuels.9b00023 Energy Fuels XXXX, XXX, XXX−XXX