Factors and Mechanisms Governing Wettability Alteration by

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FACTORS AND MECHANISMS GOVERNING WETTABILITY ALTERATION BY CHEMICALLY TUNED WATERFLOODING: A REVIEW Prakash Purswani, Miral S. Tawfik, and Zuleima Karpyn Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b01067 • Publication Date (Web): 10 Jul 2017 Downloaded from http://pubs.acs.org on July 11, 2017

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FACTORS AND MECHANISMS GOVERNING WETTABILITY ALTERATION BY CHEMICALLY TUNED WATERFLOODING: A REVIEW Prakash Purswani *, Miral S. Tawfik *, Zuleima T. Karpyn # John and Willie Leone Family Department of Energy and Mineral Engineering, The Pennsylvania State University, University Park, Pennsylvania, USA

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Enhanced oil recovery (EOR) techniques aim at improving the recovery efficiency of mature oil

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fields in secondary and tertiary recovery modes. In particular, chemically tuned waterflooding

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has been a rising EOR technique towards improving oil recovery from rocks that are difficult to

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produce due to their initial wetting state, e.g., oil-wet and intermediate-wet. With an increasing

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oil-wetting affinity of a reservoir rock, extraction of oil becomes more challenging. As such,

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wettability alteration has been identified as the primary mechanism for oil recovery from oil-wet

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and intermediate-wet rock types. Recently, researchers have attempted to categorize the factors

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and mechanisms governing wettability alteration by chemically tuned waterflooding. Multiple

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studies have identified the importance of brine salinity and ion composition on promoting

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wettability alteration to a more favorable water-wet state. Reservoir temperature, the surface

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charge of the rock, and the surface active components of crude oil are also reported to influence

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wettability alteration and therefore, oil recovery from waterflooding. In this paper, we present an

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extensive literature review on the subject of wettability alteration, with an emphasis on

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experimental work conducted on carbonate and sandstone rocks, as they constitute the majority

*

These authors contributed equally

#

Corresponding Author: Zuleima T. Karpyn 151 Hosler Building University Park, PA 16802 The Pennsylvania State University Ph. (814) 863-2273 Fax. (814) 865-3248 [email protected] ABSTRACT

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of the oil reserves in the world. The purpose of this review paper is to synthesize the current state

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of knowledge regarding the factors and mechanisms that govern wettability alteration by

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chemically tuned waterflooding and, through this exercise, set the platform to pose new research

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questions.

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Keywords: chemically tuned waterflooding; wettability; surface active components; salinity; ion

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composition.

38 39

1. BACKGROUND ON WATERFLOODING

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In 1865, the first waterflood occurred by an accidental water leak from shallow sands in the

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Pithole City area in Pennsylvania, USA.1 A significant increase in oil recovery was observed and

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attributed to the flow of water through the oil sands, which displaced the oil and increased the

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reservoir pressure upon the depletion of the reservoir’s natural energy. Since then, waterflooding

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has been slowly growing in applicability until the 1950s, at which time it was recognized as the

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leading secondary oil recovery mechanism.1

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Reinjection of produced water has been the most common practice in waterflooding to avoid

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formation damage, as well as to dispose and make use of produced water. However, volumes of

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produced water are rarely sufficient to replenish the reservoir energy. In addition, the use of

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produced water requires more complex surface facilities to separate suspended solids, oil

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droplets, and dissolved hydrocarbons, as well as the corrosive components in order to avoid

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scaling and/or corrosion in injector wells.2 Surface facilities might not be readily available on

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site, especially on offshore fields where space on platforms is limited. Hence, the injection of

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seawater has been deemed more economically and technically convenient than treated produced

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water due to its abundance, lower cost, and convenience for offshore use.2


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It has been observed through several experimental and field studies that the injection of seawater

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results in improved oil recovery, as compared to the injection of produced water,3,4 which has

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been attributed to the lower salinity of seawater compared to the higher salinity of produced

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water. Martin (1959) suggested that reducing the salinity of water could improve oil recovery in

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sandstone rocks.5 Chemically tuned waterflooding (CTWF) initially emerged in the form of low

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salinity waterflooding (LSWF), which involved the dilution of injected brine. Several laboratory

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studies have been conducted to explain the mechanism by which LSWF improves oil recovery in

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sandstones.6–8 Zhang et al. (2006) further suggested that brine composition rather than salinity

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causes improved oil recovery in carbonate rocks.9 This triggered numerous experimental studies

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that focus primarily on identifying and optimizing the key factors that affect the success of

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CTWF.

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Early on, the focus was only on understanding LSWF in sandstone reservoirs due to its less

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complex structure, as well as the common understanding that improved oil recovery due to

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LSWF is due to interactions of the injected brine primarily with clay minerals.6 On the contrary,

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carbonate rocks have minimal to no clay content,10 hence, LSWF was not believed to be a viable

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enhanced oil recovery method for carbonate reservoirs. However, Bagci et al. (2001) first

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reported improved oil recovery due to LSWF in carbonates.11 The recovery factors of carbonate

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reservoirs are lower than those of sandstone reservoirs.12 This is because of the complex

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characteristics of carbonate rocks, which arise mainly due to their initial wetting state.13,14

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Anderson (1986) defined wettability as “the ability of a fluid to spread or adhere to the rock

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surface in the presence of another immiscible fluid.”15 While most sandstone reservoirs are

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strongly water-wet or mixed-wet systems, most carbonate reservoirs are either mixed-wet or

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completely oil-wet.13,14 The term “mixed wettability” was first coined by Salathiel (1973), where


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the author suggested that reservoirs are primarily water-wet in nature during formative stages,

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but, in later stages, organic components of oil come in contact with the rock surface, rendering

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some portions of the reservoir oil-wet.16 The degree of wettability of a rock is governed by the

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nature of the crude oil-brine-rock system. The oil-wet nature of carbonate rocks can be attributed

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to the tendency of organic components from the oil to adsorb onto the surface of the rock more

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strongly, making carbonate reservoirs harder to produce. One of the earliest works on wettability

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modification was carried out by Wagner et al. (1959), where they performed a series of

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waterflooding experiments on synthetic calcite and quartz cores with brines of different salinities

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and pH to observe the positive effects of wettability modifications for improving oil recovery.17

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Furthermore, the importance of ion composition present in seawater was recognized as a critical

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factor affecting the process of wettability alteration. This led to the use of tailored brine solutions

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made from seawater in the secondary and tertiary recovery stages for improving oil recovery.

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Work has also been done on seawater flooding to prove that wettability alteration indeed plays

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an important role in improving oil recovery.9,18–23

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Many laboratory studies were conducted on carbonate and sandstone reservoirs to verify whether

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the injection of brines of different salinities and ion compositions could disturb the chemical

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equilibrium between the rock and crude oil to facilitate oil recovery. Mg2+, Ca2+, and SO42- ions

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present in seawater were experimentally proven to be the potential determining ions responsible

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for incremental oil recovery.9,19,20,24,25 Further, the contribution of the non-participating ions was

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analyzed, where it was seen that Na+ and Cl- ions did not contribute towards oil recovery and

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therefore, seawater salinity and composition could be tuned by optimizing the potential ions at

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the expense of the non-participating ions.23,26


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Despite the numerous experimental, numerical, and field studies on CTWF, there is still little

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consensus on the mechanism(s) by which it improves oil recovery.27–30 The mechanistic

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explanation for improved oil recovery by CTWF in carbonates is even less explored compared to

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sandstone reservoirs.30 This lack of understanding of the underlying mechanism(s) of CTWF

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leads to inconsistency in the reported results, where some experimental studies report an

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improved oil recovery by CTWF,31–33 while others report no additional recovery.34,35,36 The

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primary focus of this work is to document and analyze experimental work done thus far about

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CTWF as a potential EOR technique, provide a comprehensive report of the key factors affecting

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the success of CTWF, and propose mechanisms by which CTWF improves oil recovery in

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carbonate and sandstone reservoirs. Some of the most relevant experiments discussed in this

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literature review are presented in Table 1, as a comparative presentation of tested conditions and

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reported gains in oil recovery. The effects of surface properties of the rock, crude oil and brine

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composition, the salinity of the imbibing fluid, and reservoir temperature, together with

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characterizing techniques like zeta potential measurement and acid number measurement, have

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been studied to understand the interactions that take place at the oil/rock/brine interface. This

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paper presents a comprehensive literature review in the area of wettability alteration for

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enhancing oil recovery and, it is intended to assist further development of the existing and

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emerging mathematical models for predicting oil recovery through CTWF. In addition, we

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explore a series of research questions and expose knowledge gaps that could guide further

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studies to improve our understanding of wettability alteration via CTWF.

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Table 1: A summary of coreflooding experiments performed on carbonate and sandstone cores

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for a range of experimental temperatures, recovery modes, and brine compositions. Sands are

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highlighted in gray. References

Core Analyzed

Recovery Mode

Temperature

Brine/ions in consideration

Wettability Analysis

% Oil Recovery

Suggested Mechanism

contact angle measurement on flat polished surfaces.

-

pH modification

-

71 - 84 % OOIP

fines migration

Wagner, O.R. et al. (1959)17

unconsolidated sand cores

forced

-

fresh water; NaCl solutions of different salinities; HCl of different concentrations.

Martin, J.C. (1959)5

sandstone

forced

-

fresh water and brine

additional 1.7 to 12.3% of OOIP in tertiary mode.

berea sandstone Bernard, G.G. (1967)6

synthetic sandstone cores containing 2% montmorillonite

forced injection

room temperature

distilled water versus brine (15,5,1,0.1% NaCl solution)

-

additional 2.3 to 34.4% of OOIP in secondary mode

increased pressure drop; compaction by clay swelling

Puntervold et al. (2007)19

chalk

spontaneous

90 - 130 oC

Ca2+, Mg2+, SO42-

chromatographic wettability test

Zhang et al. (2007)9

chalk

spontaneous

40, 70, 100, 130 o C

Ca2+, Mg2+, SO42-


Strand et al. (2008)20

limestone

forced and spontaneous

120 oC

SO42-

ion chromatography

~ 60 % of OOIP at 130 o C additional 15 % increase

Puntervold et al. (2009) 37

chalk

spontaneous

50, 70, 90, 110, 130 oC

produced water, SW


additional 6 % increase

multi-ion exchange

Fathi et al. (2009)21

chalk

forced

100, 110, 120 oC

SW with increased NaCl; low salinity SW


5 % decrease, additional 10 % increase

multi-ion exchange

-

additional ~15 % of OOIP (LSWF in tertiary mode)

salting-in

multi-ion exchange

Austad, T. et al. (2010)38

sandstone

forced

o

40 C

+

2+

-

Na , Ca , Cl

-

multi-ion exchange multi-ion exchange multi-ion exchange

Shariatpanahi et al. (2010)24

limestone

spontaneous

70-150 oC

FW, SW and diluted SW


~ 40 %OOIP; 53 % OOIP and 63 % OOIP respectively


chalk

spontaneous

20, 50, 90, 130 o C

SO42-


-

multi-ion exchange

Yousef et al. (2011)40

composite rock samples from a carbonate reservoir

forced

212 oF

low salinity, 2, 10, 20 times diluted SW

drop angle analysis

additional 78.5 %; 9-10 % and 1-1.6% increase respectively

rock dissolution

Fathi et al. (2011)23

chalk

spontaneous

70 – 120 oC

SW depleted of NaCl and increased


additional 5 18 % increase

_


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FW and SW, and dilutions, [SO42-], [Mg2+], and [Ca2+] variations Gupta, R. et al. (2011)41

limestone and dolomite

forced injection

o

250 F

2-

PO4 in SW without SO42-

additional 5.19% of OOIP with SW4S -

chalk

spontaneous

90 oC

SW depleted with NaCl and increased with 34 times SO42-



electrical double layer expansion


25% OOIP, 30% OOIP, and 33% OOIP respectively

anhydrite mineral dissolution

chromatographic surface analysis


multi-ion exchange

Austad et al. (2015)42

limestone

forced

100 C

FW, SW and 10 times diluted SW


dolomite

spontaneous

70 oC

10 times diluted SW

o

rock dissolution and multi-ion exchange

additional 15.6% of OOIP with B(OH)4-

B(OH)4- in SW without SO42-

Puntervold et al. (2015)26

additional 21.3% of OOIP with PO42-

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2. BRINE SALINITY AND ION COMPOSITION

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Low-salinity waterflooding (LSWF) is considered a subset of chemically tuned waterflooding

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(CTWF) as it involves the overall dilution of the injected brine while maintaining a constant ion

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composition. Early experimental studies focused on LSWF in sandstone and slowly progressed

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towards carbonates.6,10,11 Several of these experiments concluded that decreasing the salinity of

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injected water leads to an increase in oil recovery, as well as a corresponding increase in the

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water-wetness of the rock in both carbonate and sandstone reservoirs.17,44–48 To illustrate the

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phenomenon of LSWF in carbonate reservoirs, zeta potential measurements were conducted by

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Yousef et al. (2012). Zeta potential, also known as “electrokinetic potential,” is useful towards

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understanding the interactions among particles in a suspension, and has been widely used for

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finding the surface charge of a rock in a particular brine environment. The measurements showed

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that as the salinity of brine decreases, zeta potential of the carbonate surface decreases, thereby,

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suggesting that Ca2+ ions from the rock surface migrate towards the low salinity brine to re-

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establish chemical equilibrium between the rock and the brine.49 This effect is commonly known


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as mineral dissolution and is considered one of the possible mechanisms contributing to an

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improvement in oil recovery by CTWF in carbonate rocks. Also, the decrease in the positive

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charge on the carbonate surface, when exposed to low salinity water, leads to the expansion of

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the electric double layer (EDL), which results in a thicker, more stable water film. EDL

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expansion is also considered one of many mechanisms used for explaining wettability alteration

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by LSWF that highly depends on the electrostatic interaction between the brine/oil and

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brine/rock interfaces.50,51 A similar trend in the results was obtained by Alotaibi et al. (2011),

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where zeta potential values of sandstone rocks with differing clay contents were measured in

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brines of different salinities. It was observed that as the brine salinity was decreased, there was

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an increase in zeta potential magnitude for all sandstone rock types, suggesting a thicker EDL

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with a lower salinity brine.52

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With the advancement in technology, techniques like X-ray micro-computed tomography

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(micro-CT) have been used to study the effect of LSWF. This pore scale methodology helps to

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track fluid flow behavior during waterflooding techniques in porous media. In the study

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conducted by Khishvand et al. (2016), micro-CT image analysis was used to investigate in-situ

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changes that occurred in fluid saturations via wettability alteration upon waterflooding with

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brines of different salinities in sandstone rocks.53 They reported higher oil recovery for the brine

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of lower salinity, suggesting that wettability alteration, caused due to mineral migration and/or

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multi-ion exchange at the rock surface, potentially enabled the deeper invasion of the brine into

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larger oil-filled pores to improve oil recovery. This was analyzed by measuring oil-water contact

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angles using high resolution images captured during the experiments.53 Although the majority of

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the experimental studies report a gain with LSWF, it is valuable to note that the injection of low

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salinity brine, incompatible with the formation water, could lead to formation damage and


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consequently a decrease in production. Therefore, maintaining an optimum salinity level, in

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which the improvement in oil recovery outweighs formation damage, is crucial. 5,6

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In 1999, the effect of injected brine composition rather than overall salinity was first

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experimentally investigated by coreflooding and spontaneous imbibition experiments using

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Berea sandstone cores.45 Further studies investigated the effect of individual ions in seawater,

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including Ca2+, Mg2+, SO42-, Na+, and Cl-. Almost all experimental results concluded that Ca2+,

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Mg2+, and SO42- are potential determining ions, owing to the tendency of these ions to influence

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the rock surface charge by altering the wettability to a more water-wet system.25,54,55 It is worth

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noting, however, that the overall salinity (ionic strength) of the injected brine influences the

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activity of the potential determining ions, which is in accordance with the modified Debye-

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Hückel model that states that the activity coefficient of individual ions in a solution can be

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determined using the following equation: − log =

√ 1 + √

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where is the activity co-efficient of ionic species i, zi is the charge of ionic species i, I is the

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ionic strength of the solution, A & B are constants depending on temperature and dielectric

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constant, and ai is the effective diameter of the ion. Hence, both ion composition and salinity are

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key parameters for engineering an optimum injection brine for maximum incremental oil

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recovery.56

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Zeta potential measurements of rock particles suspended in brine solutions have also been

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valuable in identifying these potential determining ions responsible for improving oil recovery. It

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was found that both Ca2+ ions and SO42- ions are able to change the surface charge of chalk

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particles when added to the chalk suspension.57 This was further verified in the work by Zhang

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and coworkers (2006, 2007), where the zeta potential of chalk suspension was measured at a


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fixed pH of 8.4 by increasing the concentration of the potential determining ion in consideration.

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They observed that increasing Mg2+ and Ca2+ ion concentrations increased the zeta potential of

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the rock sample, owing to the affinity of these ions towards the rock surface. For SO42- ions, a

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decrease in zeta potential was observed with an increasing SO42- ion concentration, owing to the

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possible adsorption of the negative ion onto the rock surface.9,54

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Tang and Morrow (1999) studied the effect of cation valency on the performance of low-salinity

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waterflooding in sandstones.45 Monovalent (Na+), divalent (Ca2+), and trivalent (Al3+) cations

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were used in different injection brines. The study suggested that, at relatively higher salinities,

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lower valence cations lead to a higher recovery by spontaneous imbibition. The presence of

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higher valence cations promotes the adsorption of polar organic compounds onto the negatively

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charged sandstone rock surface by “cationic bridging,” thus decreasing its water-wetness, and

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consequently, trapping more oil and leading to lower recovery. However, at lower salinity, the

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effect of cation valency on the wetting condition and oil recovery was less significant.45 As

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opposed to the conclusion arrived at by Tang and Morrow (1999) for sandstones, coreflooding

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and spontaneous imbibition of oil from carbonate cores (particularly limestone) show that an

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increase in divalent cation concentrations (Ca2+ and/or Mg2+) in injected brine, and a decrease in

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monovalent cations (Na+), lead to an increase in oil recovery in the presence of SO42-

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ions.20,25,54,55 This can be explained by the adsorption of SO42- ions onto the positively charged

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carbonate surface at the brine-rock interface, which, in turn, leads to the attraction of Ca2+ and

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Mg2+ closer towards the carbonate surface. In addition, at the brine-oil interface, divalent cations

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form bonds with the carboxylate groups (R-COO-) in crude oil, thus decreasing the chances of

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re-adsorption of oil onto the carbonate surface.58


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In the study by Gupta et al. (2011), coreflooding experiments were performed to investigate the

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effect of replacing sulfate ions with other anions, including Phosphate (PO42-), and Borate

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(B(OH)4-).41 The coreflood experiments were performed on several limestone and dolomite cores

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in tertiary mode, where the cores were first flooded with formation water, then with chemically

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tuned water. It was observed that adding four times the amount of SO42- ions in seawater resulted

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in an additional recovery of 6% of the original oil in place (OOIP). Replacing SO42- ions with

212

B(OH)4- ions caused an incremental recovery of 15.6% of OOIP, whereas replacing SO42- ions

213

with PO42- ions led to an even higher incremental recovery of 21.3% of OOIP.41

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Connate water is also identified as a primary factor for a successful LSWF in sandstone

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reservoirs, without which there is no additional oil recovery.45,59 This is because the connate

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water saturation history and ion composition dictate the stability of the water film formation over

217

the rock surface, and therefore, has a direct effect on the initial wetting condition of the rock.

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Most experimental studies pertaining to CTWF focus on the effect of the salinity and

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composition of injected brine on oil recovery, whereas very few studies attempt to investigate the

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effect of connate water properties on oil recovery. A study conducted by Shehata et al. (2016)

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investigated the effect of connate water salinity and concentrations of different cations on the

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performance of LSWF in two types of cores: Bandera, and Buff Berea sandstone cores.46 The

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study did not focus on the effect of the concentration of anions because connate water normally

224

has a low concentration of sulfate ions. This is partially due to the precipitation of anhydrite

225

(CaSO4), especially at higher temperatures.39,60 The study concluded that a higher salinity

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connate water results in a higher incremental recovery (7% of OOIP) by LSWF. Also, connate

227

water with a particularly high concentration of cations (Na+, Ca2+, and Mg2+) resulted in a higher

228

incremental oil recovery when a low salinity brine is injected. However, higher concentrations of


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divalent cations in connate water resulted in a higher incremental oil recovery. These conclusions

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are consistent with the explanation provided earlier, where, in sandstones, higher salinity and

231

higher valence cations lead to thin unstable water films on grain surfaces, and therefore,

232

promotes the cationic bridging of crude oil onto the clay surface, which in turn results in an

233

increased initial oil-wetness and more trapped oil that can then be recovered by means of CTWF.

234

Open Questions

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Experimental studies conducted thus far focus on the effect of potential determining ions on

236

recovery. The effect of other ions in seawater has not been explicitly investigated, including

237

HCO3- and K+. Also, the effect of SO42- ions has been widely studied due to its presence in

238

seawater. However, a high SO42- ion concentration increases the risk of reservoir souring and

239

scaling.25 Hence, the effect on oil recovery of replacing SO42- ions with other anions such as

240

borate and phosphate, and their behavior, needs to be further examined.41 Exploring the

241

possibility of using anions other than SO42- to find the optimal injection brine composition is key.

242

Other anions such as Nitrate (NO3-) can have lower associated risks and operational problems

243

compared to SO42- ions, and therefore, its ability to improve oil recovery needs to be

244

investigated. In addition, only a few studies tackled the effect of connate water on the

245

performance of CTWF. The effects of salinity and cation valence have been addressed in the

246

study by Shehata et al. (2016). However, the effect of different anions in the connate water on

247

the performance of LSWF has not been studied because formation water has more cations than

248

anions.61 More importantly, the effects of salinity and the composition of connate water on

249

incremental oil recovery via CTWF need to be quantified as connate water properties that will

250

significantly affect the optimum injection water design due to the inevitable injected and in-situ

251

brine mixing in the reservoir.


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3. MINERAL COMPOSITION OF THE ROCK

254

One important factor that is often neglected when comparing results from various studies is the

255

fact that reservoirs are often heterogeneous systems. Due to the reactive nature of chemically

256

tuned waterflooding (CTWF), and its dependence on oil/rock/brine interactions, understanding

257

the effect of rock properties on the success of CTWF is necessary for valid comparisons.

258

Different rock types greatly differ in mineral composition, which directly impacts the nature of

259

the surface charge of the rock, and it is therefore important in deliberating the initial wetting state

260

of the reservoir.

261

Carbonate reservoirs are normally composed of a variety of minerals, primarily calcite (CaCO3),

262

dolomite (CaMg(CO3)2), anhydrite (CaSO4), and quartz (SiO4). The degree of improvement in

263

oil recovery has been observed to vary based on the mineral composition of carbonate rocks.58

264

According to Austad et al.,62 injecting diluted seawater into chalk cores resulted in a drastic

265

decrease in oil recovery compared to injecting seawater. This showed that low salinity

266

waterflooding is not the reason for improved oil recovery in chalk. In the same study, coreflood

267

experiments were performed on limestone core samples―one that did not contain an anhydrite

268

mineral as part of its composition, and on another limestone sample that did. The study

269

concluded that LSWF effect could only be seen in the presence of anhydrite, indicating that the

270

presence of anhydrite plays an important role towards wettability alteration.62 Injection of low-

271

salinity water into carbonate cores in the presence of anhydrite promotes the dissolution of

272

anhydrite due to the low concentration of Ca2+ in the injected brine compared to that of

273

formation water (common ion effect). Anhydrite dissolution leads to the in-situ generation of

274

free SO42- ions, which adsorb onto the positively charged carbonate surface and catalyzes


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desorption of carboxylic groups, altering the wettability to a more water-wet state and thereby

276

improving oil recovery. On the other hand, the injection of the same low-salinity water into

277

limestone cores in the absence of anhydrite shows no improvement in oil recovery. This shows

278

that the presence of anhydrite is necessary for improved oil recovery in carbonate rocks, where

279

the injected brine contains minimal SO42- ions. It has been experimentally observed that the

280

dissolution of anhydrite is dependent on temperature, connate water salinity, and concentration

281

of Ca2+ ions in the injected brine.39

282

In the study conducted by Shariatpanahi et al. (2016), a comparison between the low salinity

283

effect in Silurian outcrop dolomite cores, and in chalk and limestone from previous studies, was

284

presented.43 The study concluded that similar to limestone rocks, the presence of sulfate ions

285

(whether in the injected brine or as a result of dissolution of anhydrite) is critical to observing

286

wettability alteration, as well as an improvement in oil recovery. However, the extent of

287

adsorption of sulfate ions onto the dolomite surface is observed to be weaker compared to chalk

288

and limestone cores. This was also confirmed in the study performed by Mahani et al. (2015),

289

where chemically tuned waterflooding in dolomites showed a smaller, or no contact angle

290

change compared to limestones (which are mainly composed of calcite), implying fewer

291

wettability modifications, as well as stronger adhesion forces between dolomite and oil.63 Also,

292

contrary to outcrop limestones, outcrop dolomite responds to chemically tuned water in the same

293

way as reservoir dolomite cores.43

294

Sandstone reservoirs, on the other hand, are composed of different minerals, most commonly

295

quartz and feldspar. These minerals make up the matrix and are bound by secondary minerals,

296

known as “cement” that form after the deposition of the sandstone matrix. There is a wide

297

variety of minerals that make up cement, including anhydrite, dolomite, and clay minerals such


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as kaolinites, chlorites, and illites, which are non-swelling clays, as well as montmorillonites,

299

which are swelling clays.64 In sandstones, clays are believed to play a significant role in the

300

success of chemically tuned waterflooding due to their abundance and large specific surface area

301

compared to matrix-forming minerals.34 However, clays that swell and clays that have positive

302

zeta potential are considered detrimental to oil recovery. Studies by Tang and Morrow (1999),

303

and Wickramathilaka et al. (2011) suggest that sandstone core samples with higher clay content

304

exhibit higher incremental recovery. However, none of these studies reported which type(s) of

305

clay minerals have a greater impact on the low-salinity effect.8,65 According to Rezaei Gomari et

306

al. (2015), both the amount and the type of clay play a significant role in low-salinity

307

waterflooding.66 Some clays act as cation exchangers, whereby clays tend to swap or exchange

308

cations with cations from the fluids in the pore space due to the deficiency in their positive

309

charge, which must be countered by cations from the surrounding formation water if the clay

310

particles are to remain electrically neutral.67 Cation exchange capacity (CEC) is a measure of the

311

excess negative charge on the clay particles. CEC varies by clay type in the following

312

descending order: montmorillonites, illites, and kaolinites.68 According to Austad et al. (2010),

313

clays with higher CEC, coupled with the presence of divalent cations in formation water, and co-

314

adsorption of these cations and the polar oil components on the clay surface, are more favorable

315

for observing low-salinity effects.38 Additionally, it was noted in this study that for clayey

316

sandstones, the main parameter that needs to be optimized in the injected brine is the

317

concentration of divalent cations, which should be low. An experimental study conducted by

318

Cissokho et al. (2010) confirmed these findings, where an incremental oil recovery of 10% was

319

observed when a sandstone core sample with 9.2% clay content was flooded with low-salinity

320

brine.69 The clays included chlorite, muscovite, and illite, which indicates that the low-salinity


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321

effect can be witnessed in the absence of kaolinite. On the other hand, other studies suggest that

322

kaolinite is considered a requirement for effective low-salinity waterflooding, due to its oil-wet

323

nature and high surface charge density, which makes its surface electric effect much greater

324

when compared to other clay minerals.70 The study concluded that a variation in kaolinite

325

content from 5 to 30% results in a change in the overall cation exchange capacity (CEC) of 47 to

326

270 eq/m3, which translates to ~2.65% incremental recovery at 30% kaolinite content. The

327

importance of kaolinite mineral was also investigated in the pore scale study conducted by

328

Lebedeva et al. (2011). The authors used X-ray micro-CT imaging to quantify the effect of

329

LSWF via wettability alteration on sand packs coated with or without kaolinite mineral.71 Micro-

330

CT image analysis helped track oil-blob occupancy changes that occurred during waterflooding

331

experiments. They found that, for the sand packs coated with kaolinite mineral, low salinity brine

332

injection improved oil recovery as opposed to the high salinity brine, suggesting that the oil-

333

wetness caused due the presence of kaolinite mineral was altered to a favorable water wetting

334

state, facilitating oil recovery. Due to the lower resolution of the micro-CT images (sufficient for

335

distinguishing oil, brine and rock entities to suitably quantify fluid saturations), wettability

336

analysis was performed using receding and advancing oil-drop contact angle measurements

337

conducted on quartz slices that mimicked the rock used for waterflooding experiments. These

338

confirmed the process of wettability alteration during LSWF.71

339

Carbonate rock surfaces are mostly positively charged, whereas sandstone rock surfaces are

340

negatively charged. The positive charge on the carbonate surface can be attributed to the

341

hydration of the calcite surface to form >CaOH2+,58 whereas the negative surface charge in the

342

case of sandstones is attributed to the presence of negatively charged clay particles as described

343

previously.15,58 The surface charge of the rock is sensitive to changes in the surrounding


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environment, including the ionic concentration and pH of the brine around the rock, which in

345

turn affects the wetting state of the rock.15 Therefore, efforts have been made to carefully

346

measure the rock surface charge in different brine environments to more accurately study the

347

interactions of oil and brine with the rock surface. One approach of estimating the surface charge

348

of the rock is through zeta potential measurements as described earlier. In the work by Vdovic

349

and Biscan (1998), zeta potential values of synthetic and natural calcite in simple NaCl brine

350

environment were investigated. They found that the zeta potential value of synthetic calcite was

351

positive at lower pH due to the prevalence of positive surface species like Ca2+, CaHCO3+,

352

whereas, natural calcite showed negative zeta potential, which was attributed to the adsorption of

353

organic material onto the calcite surface.72 As CTWF gained momentum in the oil industry, zeta

354

potential measurements were performed in more complex brine environments. Experiments

355

conducted by Mahani et al. (2015), focused on the importance of ion composition and pH of the

356

brine system on the oil/rock interface.30 Zeta potential of carbonate rock samples and oil droplets

357

were measured as a function of pH, in different brine environments, namely, formation water,

358

seawater, and diluted seawater. An increase in the zeta potential values was seen for both

359

dolomite and limestone rock particles with an increasing pH for all brine systems, suggesting

360

that the surface of the rock acted more positively charged at higher pH ranges, whereas, at lower

361

pH ranges, the rock particles showed a negative zeta potential owing to the increased adsorption

362

of SO42- ions in seawater.30 In a different set of experiments performed by Karimi et al. (2015),

363

the zeta potential of carbonate rock samples was measured both before and after aging,73 which

364

is the accelerated process of exposing the core sample to reservoir conditions in order to assist in

365

the development of an initially oil-wet sample.74 This helped in finding the change in the nature

366

of the surface charge, which is necessary for understanding the surface wetness. They found that


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367

the zeta potential of the rock sample changed from +29.6 mV to -33.4 mV for pre-aged and post-

368

aged calcite samples, respectively, at a pH of 8. The positive nature of the surface charge before

369

aging was attributed to the prevalence of positive divalent Ca2+ and Mg2+ ions present in the

370

calcite sample below pH of 10. The authors suggested that at a higher pH, the calcite surface acts

371

more negatively charged due to the possible adsorption of CO32- ions. The negative nature of the

372

surface charge post-aging was attributed to the adsorption of polar oil components onto the rock

373

surface, making the rock surface more negatively charged.73 The variety of experimental work

374

on zeta potential measurements clearly showcases the variation in the surface charge response of

375

the rock samples with different injected brine properties, indicating that rock properties have a

376

significant effect on the performance of CTWF.

377

Open Questions

378

The inconsistencies observed in experimental results using sandstone cores show difficulty in

379

generating repeatable and reproducible data due to the heterogeneity of the sandstone rock

380

mineralogy, as well as the wide variety of clays involved. The contradictions in the experimental

381

studies on sandstones can also be attributed to the interplay of several pore-scale mechanisms,

382

contributing to the overall low-salinity effect. Controlled experiments have been conducted on

383

carbonates to assess the effect of particular minerals such as calcite, dolomite, and anhydrite on

384

the performance of CTWF. However, more controlled experiments are yet to be conducted to

385

map the effect of different minerals and clay types in sandstones.

386

In addition, some studies suggest that zeta potential varies with particle size,75 however, there

387

has been little work focusing on the sensitivity of zeta potential to particle size. Further, most

388

conventional methods of measuring zeta potential at a laboratory scale, like the electrophoretic

389

mobility measurements or the electroacoustic measurements, assume that zeta potential does not


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390

depend on particle size.76 However, Nakatuka et al. (2015), studied the importance of particle

391

size distribution on zeta potential by the application of the liquid sedimentation method. They

392

discovered that the negative zeta potential values for the silica particles do indeed depend on the

393

particle size, such that, the zeta potential values increased with the decrease in particle size. The

394

authors attributed the increase in the zeta potential values to particles with smaller size, due to

395

the increased random movements of smaller particles rather than larger particles.76 Therefore, the

396

reliability of zeta potential measurements at the laboratory scale, and their true interpretation at

397

the field scale, remain an area of investigation.

398 399

4. CRUDE OIL COMPOSITION

400

Heavier components of crude oil, like asphaltenes or resins, are believed to carry compounds

401

bearing oxygen, nitrogen, and sulfur atoms.77 These compounds are responsible for the acidity

402

and/or basicity of crude oils. Tests done by Seifert and Howell (1969) confirmed the presence of

403

carboxylic groups in California crude, which, the authors suggested, were active at a particular

404

pH of the system.78 Fathi et al. (2011) further reinforced that the wetting properties of crude oil

405

were affected by the chemical properties of the carboxylic material present in the crude oil.79 The

406

presence of carboxylic acids in the crude oil was further confirmed by the electrokinetic study

407

conducted by Mahani et al. (2015). They measured the zeta potential of oil droplets, as

408

suspended particles, in different brine environments and observed that the oil particles showed a

409

negative zeta potential over the range of pH measurements in different brine salinities, owing to

410

the presence of negative carboxyl groups in the crude oil.63

411

It is therefore understood that the acidic and basic components present in the crude oil are crucial

412

in understanding the extent of the adsorption of hydrocarbon components on the rock surface, as


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413

well as the initial wetting characteristics of rocks.15,80 According to Zhang et al. (2007), in order

414

to obtain a satisfactory oil recovery from carbonate reservoirs with low water wetness, initial

415

wetting conditions must be altered.17 For carbonate rocks, where the surface is primarily

416

positively charged, the adsorption of the negatively charged acidic components from the crude

417

oil plays a key role in determining the potential for oil recovery from these reservoirs. Therefore,

418

the quantification of the acidic content of crude oil has gained importance in the recent past.

419

One way of quantifying the amount of acidic or basic components in crude oil is through acid

420

and base number measurements. The widely accepted method for estimating these measurements

421

is by potentiometric titration. Standardized workflows were developed by the American Society

422

for Testing and Materials (ASTM) and have seen several revisions over time. The most updated

423

revisions are ASTM D664 (2011) for acid number measurements81 and ASTM D2896 (2015) for

424

base number measurements82. In recent years, there have been improvements in the application

425

of these methods. One widely accepted improvement in the measurement of acid number was

426

proposed by Fan and Buckley (2007). They suggested that the application of a small quantity of

427

spiking solution, prepared by the addition of a small concentration of stearic acid, could assist in

428

achieving clear inflection points. This method also led to a much lower consumption of valuable

429

crude oil.80

430

With the importance of the acid number of crude oil towards improving oil recovery, together

431

with the ease of acid number measurements, more research has been performed to explore this

432

domain. In the work by Stadness and Austad (2000), it is seen that the oil recovery was about

433

70% when the acid number was 0 mg KOH/g, implying that the oil had no acidic polar

434

components to adsorb onto the rock surface, indicating a water-wet system. On the other hand,

435

when the acid number increased up to 1.73 mg KOH/g, oil recovery decreased dramatically.18


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Similar observations were found in the work conducted by Fathi and coworkers (2010, 2010,

437

2011).21–23 Several spontaneous imbibition experiments were performed on cores aged with oils

438

of different acid number, where the acid number of each crude oil was tailored by extracting the

439

acidic components from the oil. It was observed that the oil with the maximum quantity of acidic

440

components showed the least recovery, as well as the lowest water-wet fraction at the end of the

441

recovery process.22,79 This was also validated in the surface complexation model developed by

442

Qiao et al. (2015), which predicted a lower recovery potential by increasing the acid number of

443

the crude oil.58 These studies suggest that the acid number of the crude oil plays a critical role in

444

determining the incremental oil recovery and whether a reservoir could be considered a good

445

candidate for chemically tuned waterflooding.

446

Open question

447

The investigation of acid number emphasizes the importance of organic acids present in crude oil

448

towards enhancing oil recovery. However, there is little understanding about the origin of the

449

acidic groups in the crude oil, which could be attributed to the oxidation process that occurs

450

during the developmental stages of hydrocarbon formation. It is understood that underground

451

water plays a key role in transporting the crude oil to its producing zone in the reservoir. It can

452

be inferred that in the process of this migration and interaction with water molecules, the

453

hydrocarbons are oxidized and begin to possess the acidic groups. However, little experimental

454

work supports this argument. In addition, acid number measurement is not an accurate way of

455

identifying the amount of acidic components in oil that are reactive with, and have an affinity to,

456

the rock surface (i.e. acidic components with surface active species). It is rather a measure of the

457

total acidic components in oil, both reactive and non-reactive. According to Hoeiland et al.

458

(2001), identifying the acid type and molecular structure is more important than measuring the


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459

amount of acids in regards to interfacial and wettability properties.83 Hence, additional

460

experimental studies are needed for a more accurate quantification of the effects of different

461

types and structures of polar components that contribute to the initial oil-wetting extent of the

462

reservoir rocks.

463 464

5. EFFECT OF TEMPERATURE ON SURFACE REACTIONS

465

Due to the reactive nature of chemically tuned waterflooding, temperature is a crucial factor that

466

affects the wettability alteration process. The role of temperature is two-fold, as it affects the

467

activity of the ionic species present in the brine, as well as the interaction of the polar organic

468

compounds in crude oil with the rock surface. Together, these can affect the type of chemical

469

reactions that take place at the oil-water and fluid-rock interfaces.

470

In the experiments conducted by Zhang et al. (2006) and Austad et al. (2005), an increase in oil

471

recovery was observed along with an increase in temperature through spontaneous imbibition

472

from chalk.3,54 This improvement was attributed to the higher affinity of SO42- ions to the

473

carbonate surface at higher temperatures, which results in the displacement of the negatively

474

charged carboxylate groups (R-COO-) of the sulfate ions onto the positively charged carbonate

475

surface, freeing the oil from the rock surface, and altering the wettability of the rock to a more

476

water-wet state.3,25 This relation between the improvement in oil recovery and the increased

477

adsorption of sulfate ions onto the carbonate surface at elevated temperatures has been further

478

verified using the chromatographic wettability test developed by Strand et al. (2004), where an

479

increase in the degree of water-wetness was simultaneously observed along with a decrease in

480

the concentration of sulfate ions in the effluent at higher temperatures.84


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481

In the absence of sulfate ions in the injected fluid, as discussed in section 3, an improvement in

482

oil recovery due to low-salinity waterflooding can still be observed in carbonates, but only in the

483

presence of anhydrite minerals. However, the dissolution of anhydrite is adversely affected by an

484

increase in temperature, where higher temperature results in a lower dissolution rate.39,60

485

Additionally, the efficiency of wettability alteration increases as temperature increases.62 Hence,

486

a reduced dissolution rate can be compensated by a higher wettability alteration efficiency, and

487

vice versa. It is therefore critical to understand what type of chemical reactions are taking place

488

in the system based on the ionic composition of the brine and the rock mineralogy. Further, it is

489

also important to see which of these reactions are more active, and at which particular

490

temperature.

491

In the electrokinetic study conducted by Alotaibi et al. (2011), they measured the zeta potential

492

of the limestone and dolomite particles in different brine environments, and at different

493

temperature values. They observed that in a seawater environment at a pH of 7 at 25 oC, the zeta

494

potential of limestone was about +6.8, suggesting a positive charge of the limestone surface.

495

Further, when the temperature was increased to 50 oC, they observed a decrease in zeta potential,

496

owing to the increased dissolution of Ca2+ ions from the limestone surface due to the higher

497

activity of these ions at the elevated temperature. Similar results were obtained for dolomite

498

particles at higher temperatures.52

499

The activity of cations in injected brine is highly affected by temperature.

500

conducted by Zhang et al. (2007), adding Mg2+ ions resulted in a higher incremental oil recovery

501

than by adding Ca2+ ions at 100 oC.9 This was attributed to the higher activity of Mg2+ ions as

502

compared to Ca2+ ions at higher temperatures. This effect was more pronounced as the

503

temperature was further increased. The increase in the activity of Mg2+ observed at 130 oC


In the study

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504

overshadowed the effect of adding twice the amount of SO42- ions to an injected brine that had

505

Ca2+ ions instead of Mg2+ ions, where a larger incremental oil recovery (~ 20% of OOIP) was

506

observed,9 as shown in Figure 1.

507 508 509 510

Figure 1 – Spontaneous imbibition of different brines into chalk at 70, 100, and 130 ºC to study the effect of temperature on the activity of ions affecting the process of oil recovery.9

511

Another factor where temperature plays a role in CTWF is the dependence of the oil-wet

512

characteristic of carbonate rocks on temperature. This property is mostly attributed to the

513

adsorption of carboxylic materials onto the rock surface, due to their high affinity to carbonate

514

surfaces compared to other polar components that naturally exist in crude oil.85 Hence,

515

decarboxylation of carboxylic materials can lead to the wettability alteration of carbonate

516

surfaces to a more water-wet state. Thermal decarboxylation at higher temperatures is possible,

517

especially on a carbonate surface, where CaCO3(s) acts as a catalyst for the decarboxylation

518

reaction.86

519

Open Questions


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520

In the simulation work by Khorsandi et al. (2016), the authors modeled the effects of low salinity

521

waterflooding together with polymer flooding based on the concepts of reactive transport,

522

wettability alteration, reaction network, and multiphase fluid flow.87 They modeled the effects of

523

preflushing with low salinity water because of its ability to prevent the degradation of polymer

524

viscosity. The model successfully accounted for the degradation in viscosity caused by a high

525

salinity brine and was validated against the experimental work performed by Shiran and Skauge

526

(2013)88, showing a good match.87 These mathematical models are successful in predicting oil

527

recoveries, however, they do not consider all of the factors that may affect the process of

528

wettability alteration, and in particular, the importance of temperature in changing the activity of

529

the ionic species that affect recovery rates.

530

Further, there is limited understanding in the literature as to why Ca2+ ions show higher activity

531

at lower temperature ranges as compared to Mg2+ ions. Also, to the best of our knowledge, no

532

studies have been performed to identify the temperature threshold at which a shift in the activity

533

of Ca2+ and Mg2+ ions takes place, and whether this threshold changes with rock type.

534 535

6. PROPOSED

536

MECHANISMS

FOR

WETTABILITY

ALTERATION

IN

SANDSTONE RESERVOIRS

537

It has been well accepted that wettability alteration in oil-wet and mixed-wet systems is the

538

primary means for improved oil recovery (IOR) by chemically tuned waterflooding (CTWF).

539

Several authors have proposed different physico-chemical mechanisms to validate wettability

540

alteration as the primary cause for IOR by CTWF. These include Multi-ion exchange (MIE),

541

9,18,24

542

dissolution,7,31 pH modification,8,62 and in-situ emulsification. Some of these mechanisms were

salting-in,10,89 fines migration,8 electrical double layer (EDL) expansion,50,90 mineral


Energy & Fuels

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543

proposed for sandstone rocks and others for carbonate rocks. Authors have also tried to establish

544

various similarities and differences among these mechanisms.89 There still exists a lack of

545

consensus as to which mechanism is more prevalent, and under what conditions. In this section,

546

we elaborate on the proposed mechanisms that are relevant towards wettability alteration in

547

sandstone reservoirs, while section 7 discusses mechanisms relevant towards wettability

548

alteration in carbonate reservoirs.

549

6.1. Wettability Alteration by ‘Salting-in’

550

Austad et al. (2010) propose a low salinity mechanism in sandstone reservoirs, where they

551

suggest that clay particles act as cation exchangers on the sandstone surface.38 Initially, in the

552

natural state of the reservoir, both basic and acidic materials are adsorbed onto the clay surface,

553

owing to the negative surface charge of clay particles and their large specific surface area

554

compared to quartz. As shown in Figure 2, at initial conditions, clay particles are exposed to an

555

environment of formation brine, which has high salinity levels. The divalent ions in the rock

556

samples establish a chemical equilibrium with the surrounding high salinity formation brine.

557

After the low salinity water is injected, the chemical equilibrium is disturbed and the divalent

558

ions from the rock surface tend to free themselves to re-establish the chemical equilibrium.

559

Water molecules in the neighborhood help facilitate this process by dissociating into H+ and OH-

560

ions. H+ ions from the water molecules adsorb onto the clay surface, due to having the highest

561

affinity to the clay surface,67 and OH- ions remain in solution, resulting in a local increase in pH

562

near the clay surface.38 These OH- ions react with the acidic/basic material adsorbed onto the

563

rock surface, releasing them from the surface. This is described as the “salting-in” mechanism by

564

Rezaeidoust et al. (2009).89


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Energy & Fuels

565 566 567 568 569

Figure 2 Schematic representation of the “salting-in” mechanism of wettability alteration in sandstones, showing the liberation of acidic and basic components attached to the sandstone surface upon low salinity water injection.(Presented with permission, Austad et al 2010)38

570

The following reactions describe the salting-in mechanism in sandstones: − + = − + +

571

For the basic component binding to the rock surface − + = + +

572

For the acidic component binding to the rock surface − + = + +

573

6.2. Electric Double Layer Expansion

574

An electric double layer (EDL), first proposed by Von Helmholtz, is a structure that appears on

575

portions of rock minerals that are exposed to fluids in the pores, as well as at rock-fluid and

576

fluid-fluid interfaces. It refers to two parallel layers of charge. The first layer is referred to as the

577

surface charge, which comprises oppositely charged ions adsorbed onto the surface, whereas the

578

second layer, known as the diffuse layer, is composed of ions that are loosely attracted to the

579

surface charge.34 EDL expansion is dependent on the electrical surface charge and is a function

580

of the pH and salinity of the brine, as well as the cation type surrounding the clay or sandstone


Energy & Fuels

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581

particle. Zeta potential, as shown in Figure 3, is the potential measured at the shear plane of the

582

EDL and is useful towards the estimation of the double layer thickness. High pH, low salinity

583

brines result in a thicker EDL.50 A more negative zeta potential value means a thicker EDL,

584

which is indicative of a higher likelihood of water-wetting conditions.

585 586 587 588

Figure 3 Schematic representation of the Electric Double Layer (EDL) around a charged particle in a brine suspension.50

589

Lee et al. (2010) reported that the water layer thickness of the sandstone rock surface increased

590

from 10.8 to 11.8 Ao as salinity was decreased from 0.1 M to 0.001 M (6000 ppm to 60 ppm) by

591

changing the amount of NaCl dissolved in brine. However, when decreasing the salinity of brine

592

by altering the concentration of MgCl2, the water layer thickness increased from 8.1 to 14.8 Ao,

593

therefore suggesting the importance of both salinity and ion type towards the change in the

594

thickness of the double layer.90

595

As lower salinity water is injected, reducing multivalent cations, the electric double layer (EDL)

596

expands both at the oil/brine interface and at the rock/brine interface. This expansion causes an

597

overlap between both EDLs which in turn leads to an increase in the repulsive forces between


Page 29 of 41

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Energy & Fuels

598

them. Once the repulsive forces exceed the binding forces involved in cationic bridging of acidic

599

groups in oil to the clay surface, the water layer between the oil and clay surface expands, and oil

600

particles desorb from the clay surface, increasing water-wetness, and improving oil recovery.51,64

601

Also, decreasing the salinity of injected brine leads to more negative zeta potentials at both the

602

oil-brine and clay-brine interfaces, which results in a stronger water-wet state and improved oil

603

recovery.51 However, the trend of increased production as salinity decreases is not indefinite. If

604

salinity is further lowered, repulsive forces within clay minerals can exceed the binding forces

605

that keep clay particles intake. This results in de-flocculation of clay minerals and formation

606

damage.91 Hence, an optimum injection brine salinity has to be identified to avoid hindering oil

607

flow and jeopardizing oil recovery.

608 609

6.3. Fines Migration

610

Early experiments conducted by Bernard (1967) suggest that improved sweep efficiency can be

611

attributed to fines migration and clay swelling as a result of freshwater injection.6 This was

612

considered the main mechanism for improving oil recovery and was further confirmed by the

613

study conducted by Tang and Morrow (1999).8 These authors proposed an interplay between the

614

mechanical capillary forces that bind the oil particles to the fines and the viscous forces of the

615

low salinity waterflood. Further, the authors commented on the stability of the fines particle in

616

the suspension, suggesting that low-salinity water helps expand the electrical double layer,50,90

617

which assists in the stripping of fines and increased oil recovery, as shown in Figure 4.8 This was

618

also seen in the coreflood experiments by Pu et al. (2010), where an increase in pressure drop

619

was found to assist in oil recovery. The authors attributed this to the cumulative effect of

620

anhydrite dissolution and fines migration in the Tensleep reservoir in Wyoming.31 However,


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 30 of 41

621

some other authors reported little to no generation of fines or decrease in permeability changes

622

during low salinity brine injection and proposed for a mechanism based on the specific

623

interactions between the rock mineral and the organic components in the crude oil. This was

624

termed as the multi-ion exchange mechanism and is described in the following section.10

625 626 627 628 629 630 631 632

Figure 4 Schematic representation of “fines migration” mechanism of wettability alteration in sandstones showing the liberation of fines attached to the rock surface during low salinity waterflooding. (Recreated from Tang and Morrow (1999), with permission)8

7. PROPOSED

MECHANISMS

FOR

WETTABILITY

ALTERATION

IN

CARBONATE RESERVOIRS 7.1. Wettability Alteration by “Salting-in”

633

In the experiments conducted by Yousef et al. (2012)49 with carbonate rocks and low salinity

634

water injection, the authors concluded that wettability alteration takes place due to rock

635

dissolution. They proposed that a chemical equilibrium is set up in the pre-disturbed state when

636

the rock is exposed to high saline formation water. Once the system is exposed to a low salinity

637

environment, the divalent ions (Ca2+, Mg2+) present in the rocks tend to displace towards the

638

brine to re-establish equilibrium. During this process, the polar ends of the crude oil attached to

639

the carbonate surface are liberated, in a way, increasing the solubility of crude oil in the


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Energy & Fuels

640

surrounding brine, thereby improving oil recovery.49,89 This is similar to the “salting-in”

641

mechanism described in the previous section for sandstone reservoirs. Some authors describe this

642

as “rock dissolution” mechanism, which is a consequence of the process of wettability alteration

643

as the divalent ions migrate from the rock surface towards the brine.

644

7.2. Multi Ion Exchange (MIE)

645

Lager et al. (2008) proposed this mechanism based on the different interactions, including, cation

646

exchange, anion exchange, ligand exchange, protonation, cation bridging, hydrogen bonding,

647

Van der Waals interaction or water bridging, that may happen between the rock mineral and the

648

various organic functional groups present in the crude oil. Upon the injection of brine rich in

649

multivalent ions, stronger ligand bonding between the carboxylic material and the metal cation in

650

the brine overcomes the weaker cation bridging associations between the carboxylic material and

651

the rock surface. This releases the organo-mettalic complexes (RCOO-M, where M is the

652

multivalent cation) from the rock.10 A similar mechanism for carbonate rocks was proposed by

653

Zhang et al. (2007).9 The cumulative interplay of the divalent ions from the brine, together with

654

the rock and crude oil, impact the process of wettability alteration. The mechanism is a

655

sequential process that can be understood as follows: Owing to the positive surface charge of the

656

carbonate surface, SO42- ions are attracted towards the surface, lowering the surface potential and

657

subsequently attracting the divalent positive ions closer to the surface. As discussed earlier,

658

temperature plays an important role towards the activity of these ionic species. Hence, the

659

mechanism is divided into two cases with respect to temperature. At lower temperature ranges of

660

about 70 oC, the activity of Ca2+ ions is higher, and consequently, more Ca2+ ions are seen close

661

to the surface than Mg2+ ions. This is reversed at temperatures above 100 oC, where, Mg2+ ions

662

show higher activity. During the interaction of the positive ions with the SO42- ions, the positive


Energy & Fuels

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Page 32 of 41

663

ions interact with the negative carboxylic end of the crude oil attached to the carbonate surface.

664

More positive ions in the solution form a stronger interaction with the carboxylic end, as opposed

665

to the attraction between crude oil and carbonate surface releasing the oil particles off the

666

surface, resulting in improved oil recovery.9 The mechanism is summarized in the schematic

667

below in Figure 5.

668 669 670 671 672 673

Figure 5 A schematic representation of the “MIE” mechanism of wettability alteration in carbonate reservoirs showing the sequential process of liberation of the crude oil particles from the carbonate surface by a cumulative participation of the PDIs. a) Low temperature ranges below 70 oC b) High temperature ranges of above 100 oC (Adapted from Zhang et al. 2007)9

674

The following chemical reactions help explain the mechanism:89,92 − − + + = − + − + − − + !" + = − + !" − +

675


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Energy & Fuels

676

At high temperatures, Mg2+ ions, due to their higher activity, interact with the surface Ca2+ ions

677

and replace them with a process called dolomitization.9 These interactions release the Ca2+ ions

678

from the surface which react with the crude oil at the surface releasing the carboxylic material.

679

The simulation model developed by Qiao et al. (2015) is based on this mechanism for altering

680

wettability and for predicting incremental oil recovery from mixed wet carbonate reservoirs.93

681

The model accounted for the effect of the surface active components in the crude oil, the surface

682

charge of carbonate rock and temperature. It was successfully validated against the coreflood

683

experiments performed by Fathi et al. (2010).22

684 685

CONCLUDING REMARKS

686

Chemically tuned waterflooding is an expanding technique in enhanced oil recovery, with the

687

particular attribute of enabling wettability alteration of oil- and intermediate-wet rock systems in

688

order to assist in oil production. The success of a chemically tuned waterflood is highly

689

determined by the interplay of many factors, such as crude oil properties, brine salinity, brine

690

composition, rock mineral composition, and reservoir temperature. Proper integration of surface

691

analytical techniques like zeta potential, acid number, x-ray diffraction, elemental analysis of

692

brine etc., can be useful for the characterization of rock and crude oil compositions for

693

quantification of mineral content in the rock and acid/base content in the crude oil. These

694

analyses can be key in assessing the optimum chemical tuning of injected brine for the most

695

effective waterflood scheme. Reservoir temperature is also recognized to be a critical factor

696

impacting the activity of ionic species as is evident from the “multi-ion exchange” mechanism

697

for wettability alteration in carbonate rocks. Several other mechanisms including “rock/mineral

698

dissolution”, “fines migration”, “electrical double layer expansion”, etc., have been proposed for


Energy & Fuels

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Page 34 of 41

699

understanding wettability alteration in carbonate and sandstone reservoirs. These mechanisms

700

display both similarities and disparities in the two rock types. For instance, low salinity water

701

injection helps to disturb the chemical balance between the rock and the brine, leading to the

702

release of oil particles in both carbonates and sandstones, with the exception of those carbonate

703

rocks devoid of anhydrite mineral. Although, some studies indicate the importance of low

704

salinity brine injection in carbonate reservoirs, most point towards the role of potential

705

determining ions for improving oil recovery. A holistic understanding of these factors affecting

706

wettability alteration, and their interplay, can help improve the current understanding of the

707

simultaneous chemical reactions that occur at the rock surface. These can include salt

708

precipitation, mineral dissociation, crude oil solubilization, etc. Their appropriate identification

709

according to the crude oil/rock/brine system can lead towards the development of more robust

710

mathematical models that are better equipped to optimize waterflooding practices and oil

711

recovery estimations.

712 713

ABBREVIATIONS:

714

ASTM – American Society for Testing and Materials.

715

CEC – Cation exchange capacity.

716

CTWF – Chemically-tuned waterflooding.

717

EDL - Electric double layer.

718

EOR – Enhanced oil recovery.

719

IOR – Improved oil recovery.

720

LSWF – Low-salinity waterflooding.

721

MIE – Multi-ion exchange.


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Energy & Fuels

722

Micro-CT – Micro-computed tomography

723

OOIP – Original oil in place.PDI – Potential determining ion.

724 725

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