EOR Potential of Mixed Alkylbenzenesulfonate Surfactant at Low

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EOR Potential of Mixed Alkylbenzene Sulfonate Surfactant at Low Salinity, and the Effect of Calcium on “Optimal Ionic Strength” Thomas Tichelkamp, Hamid Hosseinzade Khanamiri, Meysam Nourani, Jan Åge Stensen, Ole Torsæter, and Gisle Øye Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b00282 • Publication Date (Web): 31 Mar 2016 Downloaded from http://pubs.acs.org on March 31, 2016

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EOR Potential of Mixed Alkylbenzene Sulfonate Surfactant at Low Salinity, and the Effect of Calcium on “Optimal Ionic Strength” Thomas Tichelkamp†, Hamid Hosseinzade Khanamiri‡, Meysam Nourani†, Jan Åge Stensen§, Ole Torsæter‡ and Gisle Øye†*

† Ugelstad Laboratory, Department of Chemical Engineering, Norwegian University of Science and Technology (NTNU), Sem Sælandsvei 4, N-7491 Trondheim, Norway. ‡ Department of Petroleum Engineering and Applied Geophysics, Norwegian University of Science and Technology (NTNU), S. P. Andersens veg 15A, N-7491 Trondheim, Norway. § Exploration and Reservoir Technology, SINTEF Petroleum Research, S. P. Andersens veg 15A, N-7491 Trondheim, Norway. *

E-mail of corresponding authors: [email protected]

KEYWORDS: Enhanced oil recovery; low salinity surfactant flooding; alkylbenzene sulfonate; calcium ions; optimal ionic strength; oil displacement efficiency.

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ABSTRACT The enhanced oil recovery (EOR) potential of different alkylbenzene sulfonate surfactants was investigated in a combined study of crude oil-water phase behavior and interfacial tension (IFT) and macroscopic oil displacement studies. In the presence of small amounts of calcium ions (calcium/sodium = 4 mol%), ultralow oil-brine IFT (< 0.001 mN/m) was observed at ionic strengths 10 times lower than “optimal salinity” with sodium chloride only; this suggested an application in low salinity surfactant (LSS) EOR. “Optimal ionic strength” was determined for different calcium/sodium ratios in the brine, which further allowed prediction of phase behavior and IFT range for a given surfactant and a given crude oil at different brine compositions. In laboratory core floods, crude oil displacement by LSS with an optimal ionic strength electrolyte was around 9 % higher than at “non-optimal” conditions.


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1. INTRODUCTION Enhanced oil recovery (EOR) by surfactant flooding has for many decades been common practice in oil fields around the world. The method consists in the injection of water with added surfactant, to reduce the interfacial tension (IFT) between oil and water. In this way capillary forces which trap oil inside the pores of the reservoir rock can be overcome to improve “microscopic” oil displacement.1 Further, o/w IFT in the range of 10-3 - 10-4 mN/m can facilitate emulsification or microemulsification of crude oil, and thus facilitate macroscopic displacement from its origin to the production well. The narrow range, in which such conditions occur, is usually referred to as “optimal salinity”, and often lies in the order of sea water or reservoir salinity.2 This, and usually high hardness of the reservoir brine, can lead to problems such as precipitation and retention of surfactant inside the reservoir, and may threaten the practical and economic success of the recovery process.3,4 Since the end of the 20th century, decent EOR potential has been suggested for the injection of desalinated water into mature oil fields. Reducing the salinity of the reservoir brine is believed to facilitate desorption of crude oil components from the surface of the reservoir rock, therewith increasing its water wettability. The EOR potential of low salinity water (LSW) flooding in sandstone reservoirs has been proven both in laboratory and field pilot tests.5,6,7,8,9,10 In recent years a hybrid between LSW and surfactant flooding, also referred to as “low salinity surfactant” (LSS) flooding, has been thoroughly studied by a number of researchers. The method relies on similar principles as conventional surfactant flooding, while low salinity (LS) and low water hardness are meant to reduce the retention of surfactant in the reservoir.11,12 Specific issues studied are the efficiency of surfactants and surfactant mixtures to decrease the oil-water IFT to values below 10-2 mN/m in an LS environment. Several experiments on laboratory scale have


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suggested reasonable improvement of oil recovery by the method, along with relatively low surfactant loss.13,14,15 Further advantage can be drawn from a pre-flood with LS water, which can additionally increase the oil recovery prior to the onset of LSS flooding. In earlier works, we studied the possibility of reducing o/w IFT to low values at an ionic strength 30 times lower than sea water salinity. This was possible mainly because the presence of small amounts of calcium increased the interfacial activity of the surfactant to a much higher degree than sodium chloride.16 The sensitivity of the system to calcium was studied systematically, and was found to be of similar nature for crude oils and saturated hydrocarbons.17 Despite clear trends in the effect of calcium on IFT at low salinity, it is still uncertain to which degree the observed effect of calcium on IFT influences oil displacement from porous rock. The main objective of the present work was to identify surfactants that could have EOR potential at low salinity conditions. Initially, phase behavior studies were carried out with four anionic surfactants. The most promising surfactant was subsequently characterized in terms of IFT reduction. Here the focus was on elucidating how small amounts of calcium ions in the aqueous phase influenced the optimal conditions. Finally, core floods were performed to investigate how the calcium ions affected the overall oil displacement efficiency during surfactant floods.


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2. MATERIALS AND METHODS 2.1. General, and liquid-liquid studies 2.1.1. Surfactants All surfactants were supplied by Unger Fabrikker AS in collaboration with CEPSA Química. The surfactants were different cuts (different chain length distributions and different degrees of isomerization) of sodium alkylbenzene sulfonates (Figure 1). All surfactants were solutions of 20 - 22 wt% sulfonate surfactant in water. Details are given in (Table 1).

Figure 1. Exemplary structure of a sodium alkylbenzene sulfonate with total chain length C18.

Table 1. Chain length distribution and CMC of the studied surfactants.

Chain length distribution CMC [g/L]*

S1

S2

S3

S4

C14 - C17

C14 - C17

C15 - C18

C10 - C18

Low degree of isomerization

High degree of isomerization

Low degree of isomerization

High degree of isomerization

0.6

0.5

0.7

1.1

* CMC values were determined from surface tension isotherms (surface tension vs. surfactant concentration), measured in milli-Q water at 22 ˚C with a CAM 200 pendant drop tensiometer (KSV Instruments Ltd., Finland). The isotherms are shown in Figure S1 (Supplementary Data).

S1 and S2 both had quite narrow chain length distributions of 14 - 17 carbon atoms. The chain length distributions of S3 and S4 were 15 - 18 and 10 - 18, respectively. In addition, S2 and S4 had higher degree of isomerization (branching) than the other surfactants. 2.1.2. Brines 5 ACS Paragon Plus Environment

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Calcium chloride dihydrate (p.a., ≥ 99%) was provided by Sigma-Aldrich Corporation and Sodium chloride (p.a., ≥ 99.5%) by Merck KGaA. Stock brine with NaCl and with different molar ratios between calcium chloride and sodium chloride ( X Ca / Na = 0.01 and 0.022), respectively, were prepared by dissolving the salts in deionized water (milli-Q water). In all cases ionic strength was I = 1.369 mol/L. The brines were diluted and mixed with 10 g/L surfactant solutions in order to achieve the proper composition for each experiment. The final surfactant concentration was always 5 g/L of surfactant.


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2.1.3. Crude Oil The oil used in this study was a stock tank crude oil from the Norwegian Continental Shelf. Its chemical and physical properties are given in Table 2.

Table 2. Physical properties and chemical composition of the crude oil (referred to as “crude A” in ref.16-18).

Composition (wt%) Saturates

61.19

Aromatics

32.42

Resins

4.93

Asphaltenes

1.46

Physical properties TAN [mg KOH/g]

1.08

TBN [mg KOH/g]

1.16 ± 0.35

Density, 15 °C [g/cm3]

0.8582

Density, 60 °C [g/cm3]

0.8252

API gravity [°API]

33.5

Viscosity, 15 °C [mPa·s]

19.90

Viscosity, 60 °C [mPa·s]

4.07

2.1.4. Phase Behavior Scan Brines in a salinity range from 0.068 - 0.680 mol/L of sodium chloride, and with constant surfactant concentrations of 5 g/L, were prepared and heated to 60 ˚C. 15 mL brine were mixed with 15 mL preheated crude oil in Pyrex® culture tubes (16 × 160 mm; borosilicate glass; screw


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cap with PTFE liner) and shaken manually. The tubes were stored at 60 ˚C in a water bath and shaking was repeated after 24 and 48 hours. Photographs were taken three days after the last shaking. No further changes in color, turbidity or relative volume of the phases were observed after that.

2.1.5. Interfacial Tension Interfacial tensions were measured using a Spinning Drop Video Tensiometer (SVT20) from Data Physics Instruments GmbH, Germany. The aqueous phase was loaded in a Fast Exchange Capillary (FEC 622/400-HT) and stored at 60 ˚C for several minutes to shorten the equilibration time during the measurement. After adding a single drop of the crude oil with a syringe, the capillary was closed with a screw lid with PTFE septum and inserted into the SVT20. The measurements were run at 60 ˚C at rotation speeds which gave cigar shaped drop profiles. The SVTS 20 IFT software was used to compute the IFT from the profile of the drops. One measurement was run for each sample, given that the results were consistent with the overall trend.

2.2. Coreflooding experiments This section gives an overview of the basic parameters of the core flooding study. The experimental conditions and results are described more detailed in ref.19 (Khanamiri et al. 2016).

2.2.1. Rock properties


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Three sandstone cores (Berea outcrop; l = 10 cm, Ø = 3.8 cm), with similar porosities (15.6 15.9 %) and similar air permeabilities (375 - 378 mD), were chosen. The rock was mainly composed of quartz (~ 92 wt%) and alkali feldspar (~ 6 wt%) and further of diopside and plagioclase.

2.2.2. Brines The composition of the high salinity in-situ brine (HS_insitu), injection brine with sodium (HS_Na) and with both sodium and calcium (HS_mix) are listed in Table 3. The last column (M2+/M+) shows the molar ratio of divalent to monovalent cations. For the LS water injection, the brines in Table 3 were diluted by the factor 10. The LS surfactant solutions were prepared by dissolving 25 g/L S3 in the LS brines. The surfactant concentration was thus five times higher than in the IFT and phase studies. This was done to account for surfactant loss by surface adsorption and phase partitioning within the core.20 A considerable amount of surfactant loss during packed bed adsorption studies has been reported in ref.19.

Table 3. Composition of the brines, given in moles per liter and TDS (total dissolved solid).

Brine HS_insitu HS_Na HS_mix

NaCl [mmol/ L] 500.5 556.1 528.3

CaCl2 × 2H2O MgCl2 × 6H2O TDS [mmol/L] [mmol/L] [mg/L]

Ionic strength M2+/M+ [mmol/l]

15.0 0.0 9.3

552.6 556.1 556.1

1.5 0.0 0.0

31140 32500 31904


0.033 0 0.018

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2.2.3. Preparation of core material The clean and dry cores were saturated with the HS_insitu under vacuum, subsequently drained with crude oil, to obtain irreducible water ( S wi = 0.18 - 0.21), and then aged at 80 °C.19

2.2.4. Flooding experiments All the flooding experiment started with LSW injection at a flow rate of 3 mL/h, which is equivalent to pore velocity of 1.3 ft/d. After around 24 - 25 h of injection the flooding rate was increased to 30 mL/h. The injection continued for 4 - 5 h with constant flow rate. Subsequent injections of surfactant solution (LSS) occurred at the same electrolyte composition. The type of injection brine and the sequence of injection are summarized in Table 4. All the flooding steps were performed at 60 °C.

Table 4. Injection sequence in different experiments; LSW and LSS describe low salinity water and low salinity surfactant. Composition of the brines HS_Na, HS_mix and HS_insitu are given in Table 3. “LS” designates 10-fold dilution of “HS” brine.

Experiment

Injection 1 (LSW)

A

LS_Na

B

C

Injection 2 (LSS)

LS_Na + 25 g/L S3

LS_Ca

LS_Ca + 25 g/L S3

LS_insitu

LS_insitu + 25 g/L S3


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3. RESULTS AND DISCUSSION 3.1. Phase behavior Figure 2 shows the phase behavior scan with crude oil and solutions of S1 - S4. Noteworthy migration of oil components occurred in samples of S2 (0.48 mol/L NaCl) and S3 (0.21 mol/L NaCl), as seen by color change and increased turbidity of the water phase. Light coloring of the water phases at increasing salinity was also observed in the samples of S1, while most samples of S4 were completely clear and only slight coloring was observed at the highest salinities. The observations confirmed that the surfactants with the longest and most branched hydrocarbon tails also were most sensitive to the addition of electrolyte. For S2, salinities higher than 0.48 mol/L resulted in strong precipitation of the surfactant. Because precipitation is highly undesired in an EOR process, S2 was excluded from further studies. For S3, the observed turbidity suggested low oil-water IFT at salinities between 0.07 and 0.27 mol/L. This is about 1/3 of sea water salinity. Despite its high sensitivity to salt, no precipitation of surfactant was observed throughout the studied salinity range. S3 was thus chosen for more extensive studies of its EOR potential at low salinity.


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Figure 2. Phase behavior of crude oil with surfactant solutions (S1 - S4) as a function of sodium chloride concentration after 3 days at 60 ˚C.

During a second phase scan of S3 with narrower salinity intervals, noteworthy turbidity was observed in the interval 0.17 - 0.27 mol/L (1 - 1.6 wt%), while samples at even lower salinity were more transparent. Samples with 0.48 mol/L NaCl and more (not shown in figure) were completely clear and almost colorless (Figure 3).


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Figure 3. Phase behavior scan of crude oil and solution of surfactant S3 (5 g/L) at different molar concentrations of NaCl.

3.2. IFT changes with salinity The spinning drop tensiometer method was used to find out whether, and under which salinity conditions, ultralow oil-water IFT and formation of microemulsions could be achieved with S3. Figure 4 shows dynamic IFT changes with sodium chloride (a), and with X Ca / Na = 0.01 (b). The dynamic trends shown are representative for all measurements at sub optimal (circles), over optimal (triangle) and optimal conditions, respectively. This is confirmed by the dynamic IFT curves in Figure S2, and by Table S1 (Supplementary Data) where the dynamic trends are ordered after their position relative to the IFT minimum.


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log(IFT/mNm-1)

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log(IFT/mNm-1)

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Figure 4. Dynamic IFT at different ionic strengths (given in the legend), in pure sodium chloride brine, and for

X Ca / Na = 0.01.

At optimal conditions, IFT usually decreased below 10-3 mN/m within a few minutes and the oil bubbles dissolved irreversibly in the aqueous phase (Figure 5); most likely, oil-in-water microemulsions were formed. At sub- or over-optimal conditions, stable oil bubbles were formed, and IFT values were between 10-1 and 10-2 mN/m at equilibrium.

Figure 5. Oil bubbles dissolve irreversibly in the aqueous phase at IFT

10−3 mN m .


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Figure 6 shows IFT values at equilibrium, plotted against ionic strength (a) and against the calcium/sodium ratio (b), respectively. In solutions with sodium chloride only, optimal conditions were found at the salinities at which strong turbidity had been observed during the phase studies (Figure 6a). Similar trends have for a long

time

been

known

for

oil-brine-surfactant

systems

with

changing

electrolyte

concentrations.21

1

1

0

0

-1

-1

-2

-2

-3

-3

-4

-4

-5

-5

Figure 6. Interfacial tension between crude oil and solutions of surfactant S3 at different salinities. (a) IFT as a function of ionic strength (I); (b) IFT as a function of the molar ratio between calcium and sodium ions ( X C a / N a ).

When the molar ratio between calcium and sodium was changed, IFT minima occurred at lower ionic strengths than with sodium chloride only. A gradual shift of the IFT minimum to lower ionic strengths came along with a strong decrease of the salinity interval in which low IFT values were achieved. The ionic strength at which the IFT minimum was observed was defined as optimal ionic strength ( IOpt ) and was clearly a function of the calcium/sodium ratios.


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In Figure 6b IFT measurements at varying calcium/sodium ratios and at a constant ionic strength of 0.02 mol/L (1/30 of sea water salinity) are shown. IFT values as low as 10-4 mN/m were obtained by slightly changing the calcium/sodium ratio. For a constant ionic strength the calcium/sodium ratio which gave optimal conditions was defined as “optimal calcium/sodium ratio” ( X Opt ). That trend was completely consistent with IFT measurements at changing calcium/sodium ratios in our earlier work on several crude oils (including the present one) and a different sulfonate surfactant.17 Optimal ionic strength was found to decrease monotonically with increasing calcium/sodium ratio and showed a tendency to leveling out beyond X Ca Na = 0.04 (Figure 7).

Figure 7. Optimal ionic strength as a function of the calcium/sodium ratio. Salinity conditions below the solid line are sub-, and conditions above the line are over optimal, respectively. Hollow symbols give the salinity conditions used for core flooding tests in the section 3.3.

Hirasaki found a linear correlation of optimal salinity to the ratio between bivalent and monovalent ions associated with surfactant micelles.4 A possible interpretation of the observed trend is, thus, that calcium association reached saturation at increasing bulk calcium/sodium 16 ACS Paragon Plus Environment

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ratios. This behavior agrees qualitatively with results from our earlier studies with the sulfonate surfactant AOT.17 Based on the intrapolation shown in Figure 7, it should be possible to select proper pairs of ionic strength and calcium/sodium ratio to gain optimal oil-water interactions. To test this assumption, three samples were chosen for dynamic oil displacement studies. All the samples had equal ionic strength (0.056 mol/L), while the calcium/sodium ratio was varied to give “sub-optimal”, “optimal” and “over-optimal” conditions (hollow items in Figure 7).

3.3. Coreflooding Three independent core floods were conducted with the ion ratios chosen in section 3.2, and are described in detail in ref.19. Initially LSW injection was performed for every core, in order to adjust its salinity to that of the subsequent LSS injection, and to investigate the effect of calcium/sodium ratio on LS oil recovery. LSS injection was then performed with 25 g/L S3 and at same salinity conditions as the previous LSW injection. Figure 8 shows the oil recovery during low salinity water (LSW) and low salinity surfactant injection (LSS) as a function of calcium/sodium ratio. The LSW injections gave oil recoveries of 54.2 - 54.9 %OOIP for all three samples, without any significant dependence on the calcium/sodium ratio. The LSS injection recovered another 20 - 30 %OOIP. The recovery was between 8 - 10 percent higher with X Ca / Na = 0.018 (optimal), than for the two other samples. For the LSS step, this is a relative increase of 43 percent for “optimal”, compared to “non-optimal” salinity conditions.


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Figure 8. Recoveries with LSW (Injection 1) and LSS (Injection 2) at three different salinity conditions (reprinted from Khanamiri et al. 2016).19

The increase in oil recovery may result from a favorable ratio between viscous forces of the displacing phase, and capillary forces which keep the oil trapped inside the rock pores. A favorable ratio is expressed by a high capillary number (Eq.1), and is here achieved by low oilbrine IFT.

Ca =

ηv γ

(1)

At constant injection velocity ( v ) and viscosity ( η ) of the injected fluid, the capillary number is reverse proportional to the IFT ( γ ) between oil and water.22 IFT reductions by three or four orders of magnitude, as observed here, can ideally increase the oil recovery by more than 50 percent.3 Another factor of importance was probably dissolution of crude oil in a microemulsion phase, which can have facilitated desorption of residual oil from the rock surface and its transport


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through the core. It may be argued that the high surfactant concentration (5 times higher than in the IFT measurements) influenced the result, and further core flooding experiments with different combinations of ionic strength and calcium/sodium ratio will be crucial to explain the correlation between calcium/sodium ratio and the reduction of residual oil saturation properly. However, as all samples had the same surfactant concentration, and IFT above CMC is in a first approximation constant with increasing surfactant concentration,23 the observed trend should give a qualitative picture of the correlation between IFT and oil production at changing calcium/sodium ratios.

4. Conclusion Four different alkylbenzene sulfonate surfactants were considered for studies on EOR by combined low salinity water and surfactant injection. A surfactant with a chain length distribution of C15-C18 (S3) was chosen for detailed studied, based on phase behavior tests with stock tank crude oil. Core flooding tests with S3 and different low salinity brines at “optimal” salinity conditions showed a strong reduction of the residual oil saturation, compared to samples with “non-optimal” conditions. The results indicate a considerable EOR potential of co-surfactant free alkylbenzene sulfonate surfactants at low salinity conditions, provided that the amount of multivalent ions inside the reservoir can be controlled by pre-equilibration during a preceding low salinity water flood and subsequent chase water or polymer floods with appropriate salinity conditions.24,25 The feasibility of latter should be subject of future extensive studies, as the sensitivity of anionic surfactants to salinity changes increases strongly in the presence of calcium.


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Acknowledgments The authors are very grateful for the financial support by our industrial partners Lundin Norge AS, Statoil, Det Norske Oljeselskap, GDF SUEZ E&P, Forskningsrådet and Unger Fabrikker AS. Unger is further acknowledged for providing the studied surfactant samples.

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EOR Potential of Mixed Alkylbenzenesulfonate Surfactant at Low

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