Experimental investigation of carbonate wettability as a function of mineralogical and thermo-physical conditions

Fuel 264 (2020) 116846

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Experimental investigation of carbonate wettability as a function of mineralogical and thermo-physical conditions

T

⁎

Muhammad Arifa,b, , Sidqi A. Abu-Khamsina, Yihuai Zhangc, Stefan Iglauerd a

Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals (KFUPM), Dhahran 34464, Saudi Arabia Department of Petroleum Engineering, Khalifa University, Abu Dhabi, 127788, United Arab Emirates c Department of Earth Science and Engineering, Imperial College London, London SW7 2BP, United Kingdom d School of Engineering, Edith Cowan University (ECU), Joondalup 6027, Western Australia, Australia b

G R A P H I C A L A B S T R A C T

A R T I C LE I N FO

A B S T R A C T

Keywords: Carbonate Wettability Mineralogy Crude-oil Roughness

Precise characterization of carbonate wettability is challenging and is broadly debated in recent past. While carbonates are known to be oil-wet, the influence of complex mineralogy, surface chemistry, and surface topographic features (e.g. surface roughness) on carbonate wettability did not receive much attention. Furthermore, despite scores of publications analyzing the influence of operating pressure and temperature on carbonate wettability, there are several contradictory trends. Therefore, to address these uncertainties associated with carbonate rock wettability, we report experimental observations of contact angles (θ) for carbonate/crudeoil/brine systems on five different carbonate samples (four real carbonate rocks and a pure calcite mineral) as a function of pressure, temperature, as well as variable mineralogy. In addition, the RMS (root mean square) surface roughness and the pertinent 2D and 3D surface topographic profiles of these rock samples were analyzed and correlated with the observed wetting behaviors. We find that increase in pressure results in an increase in θ in the low-pressure range, while relatively stable θ in high-pressure range. However, the observed θ values, follow both increasing and distinct trends with respect to temperature. Further, surface chemistry of samples suggest that calcite-based samples are relatively more hydrophilic compared to dolomitic carbonates. In addition, the RMS roughness and the corresponding 3D topographic profiles suggest that the samples with abundance of peaks demonstrated much higher θ values. These results may lead to a better understanding of the wider variability associated with the wettability behavior of carbonate rocks.

⁎

Corresponding author. E-mail address: [email protected] (M. Arif).

https://doi.org/10.1016/j.fuel.2019.116846 Received 11 July 2019; Received in revised form 2 November 2019; Accepted 7 December 2019 Available online 14 December 2019 0016-2361/ © 2019 Elsevier Ltd. All rights reserved.

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1. Introduction

surface conditions e.g. pressure, temperature, salinity, crude-oil chemical and physicochemical properties, mineralogy, surface roughness, surface chemical heterogeneity, surface cleaning method, aging conditions, etc. [1,3,33–35]. Some recent studies investigated wettability of carbonate/crude-oil/brine systems at reservoir conditions. For instance, Yang et al. [36] measured rock/crude-oil/brine contact angles on Weyburn limestone as a function of pressure and temperature using the sessile drop method and found that the contact angle increased with pressure and decreased with temperature; while Seyyedi et al. [34] investigated calcite wettability as a function of pressure and found an almost negligible dependence of contact angle on pressure. NajafiMarghmaleki et al. [37] measured wettability of four Iranian carbonate surfaces as a function of pressure and temperature. They found that the contact angles on these carbonates did not change much with pressure, while they observed a clear increase in contact angle with temperature increase for two of these carbonate samples. However, the influence of mineralogy was not explored. More recently, Alqam et al. [38] measured contact angles on four different carbonate rock samples and it was found that different rock/crude-oil pairs demonstrated different wettability. However, the measurements were primarily conducted at ambient pressure conditions. Despite the aforementioned body of literature, there is a significant uncertainty associated with the current carbonate wettability data. In addition, the degree of wetting alteration for a relatively broader spectrum of influencing factors such as pressure, temperature, and rock minerology and surface chemistry still requires more investigation. Moreover, and importantly, while the surface roughness of a rock is known to influence wettability, the effect is typically not accounted for in the reported studies. Thus, we experimentally measured the wettability of carbonate/crude-oil/brine systems via direct observation of captive bubble contact angles as a function of pressure, temperature, rock minerology, surface chemistry and surface roughness. To this end, four carbonate core samples of varying lithology and a pure calcite mineral were examined at a range of pressures (0.1 MPa to 15 MPa) and temperatures (298 K to 323 K). In addition, the influence of surface roughness was investigated by measuring 3D and 2D surface topographic profiles and the RMS (root mean square) surface roughness of the carbonate samples. These results assist to understand the carbonate wetting dynamics and thus help reduce the uncertainty associated with carbonate reservoir development.

Wettability is an important rock/fluid interaction property, which governs the multiphase flow in porous media and the fluid distribution in rock pore spaces. Precise characterization of wetting characteristics of a rock/fluid system is thus important for key oil and gas applications including enhanced oil recovery, hydrocarbon reservoir modelling, and CO2 geo-storage [1–4]. In this context, carbonate reservoirs are vital candidates for rock/ fluid interaction studies because over 60% of the world’s remaining oil is located in carbonate rock systems [5]. However, oil recovery from carbonate reservoirs during natural depletion and in the secondary and tertiary recovery stages is typically low [6], and this is partly due to the complex wetting characteristics of carbonate rocks [6,7]. For instance, during waterflooding for secondary oil recovery, a significant fraction of oil is bypassed due to the oil-wet characteristics of the candidate rock [8]. In addition, the presence of natural fractures in carbonates further lowers the oil recovery due to bypassing of injected fluid through the fractures [9]. Furthermore, the extent of spontaneous imbibition of water from fractures into the matrix blocks is dominated by the capillary forces, which in turn are controlled by the rock wetting characteristics [4,9]. Carbonate rocks are primarily composed of calcium carbonate. Common rocks in the carbonate family include limestone, dolomite, chalks and mudstones [10,11]. Calcite is a stable polymorph of calcium carbonate at reservoir conditions, and it is frequently used in research studies as a proxy mineral representative of the reservoir calcium carbonate family [12]. In terms of pore structure, carbonate rocks are characterized by complex multimodal pore-size distributions (microporosity to vug, e.g. [13]), presence of natural fractures, and physicochemical features that lead to a range of wetting characteristics e.g. from water-wet to oil-wet or even mixed-wet [9,10]. In addition, such complex pore morphology renders carbonate reservoir behavior sensitive to the fluid properties due to the chemically reactive nature of carbonates [10]. The idea of carbonate wettability characterization originated from the classic studies by Trieber and Owens [14] and Chlingar and Yen [15]. These researchers analyzed wetting characteristics of 151 carbonate rock core samples from across the globe (including USA, Middle East, China, Mexico, Canada and India). The key finding was that 80% of investigated samples were oil-wet and the remaining were water-wet to intermediate-wet. Other independent researchers suggest that an initially water-wet rock surface can transform into an oil-wet surface over time due to asphaltene deposition from crude oil [16,17]. Anderson’s wettability review series [18–21], and subsequent explanations by Buckley and co-authors [22,23] established that adsorption of asphaltentic components of crude oil onto the rock surface could alter the rock apparent wettability from strongly water-wet to a more oil-wet state. It was also pointed out that rock/crude-oil/brine interactions can be: a) ionic interactions that involve ionization of acid and bases at oil/ water and solid/water interfaces and b) surface precipitation interactions that depend on the crude-oil/solvent properties [22]. We identify that both the current and the state-of-the-art research on carbonate wettability measurements span across three broader themes, which are: a) carbonate wettability characterization at a broad range of operating conditions [24,25], b) mechanisms responsible for wettability alteration [26,27], and c) wettability alteration using chemical EOR e.g. low salinity water, nanofluid or surfactant and polymer flooding [28–32]. In all these instances, however, it is clear that a precise characterization of carbonate wettability and the associated influencing factors is of utmost significance. Typically, the rock wettability is characterized by experimental measurement of contact angle formed on a rock/mineral surface under the influence of interfacial forces. However, reliable contact angle measurements on rock surfaces at representative conditions remains a challenge since it is known to be influenced by a range of operating and

2. Materials and methods 2.1. Fluids and rock samples A crude oil sample was acquired from a producing oil and gas field and the measured physical and chemical properties of the sample are shown in Table 1. Crude oil physical and chemical properties are significant factors that influence the wetting characteristics of a rock/oil/ brine system [23,39] thus, we also list the crude oil properties of the relevant previous studies in Table 1 to allow a robust comparison. A reservoir brine sample with total dissolved solids 57,670 ppm was used in this work, the detailed composition of which is listed in Table 2. Four reservoir carbonate rock core samples (labelled as Samples A through D) of variable mineralogy and from two different geological formations were acquired. The samples were cut to a desired size and the surface roughness were measured (Fig. 1, Section 2.3). The selected sample sizes fit the circular disc of the contact angle measurement apparatus (shown in Fig. 2). In addition, a pure calcite Iceland Spar mineral (labelled sample E) was used. Table 3 presents the lithological description of the samples used. 2.2. Mineralogy, elemental composition and petrophysical properties of the rock samples studied The mineralogy of samples was determined via XRD analysis 2

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Table 1 Physical and chemical properties of crude oils used in the literature vs. this work. Reference

T (K)

Yang et al. [36] Seyyedi et al. [34] Najafi-Marghmaleki et al. [37] Al-Hammadi et al. [24] Lu et al. [40] Zhang et al. [35] This work

300 311 298 294 298 298 298

Crude Oil Physical Properties

Crude Oil SARA analysis

Surface Tension (mN/m)

Density (kg/m3)

Viscosity (mPa*s)

API gravity

Saturates (wt%)

Aromatics (wt%)

Resins (wt%)

Asphaltenes (wt%)

not reported not reported not reported not reported not reported not reported 28.42

877 875.7 not reported 830 952 950 942

13 31.25 not reported not reported 2190 747.60 124.4

not reported 28.9 not reported not reported not reported not reported 18.235

not reported 43.8 30.49 55.25 not reported 60.01 38.5

not reported 25.86 52.17 38.07 not reported 22.97 31.9

not reported 29.94 8.93 6.22 36.8 9.01 18

not reported 0.4 8.41 0.46 3.3 2.84 11.6

permeameter respectively and are reported in Table 3.

Table 2 Reservoir brine composition. Ion

Concentration (meq/L)

Na+ Ca2+ Mg2+ SO2 ClHCO3– Total dissolved solids (ppm)

56.113 43.204 32.507 30.297 19.915 14.854 57,670

2.3. Surface roughness The surface roughness of these samples was measured with a surface profilometer (Optical Profilometer, Bruker Instrument). A typical surface profilometer is a device that measures the surface roughness, surface finishes and areal topography (e.g. curvature and flatness) of a surface. Essentially, it does so by quantifying the difference between the high and low points on a surface. The profilometer uses white light via a fringe pattern projection method to scan the rock sample surface. The 2D and 3D scans are measured and analyzed using surface imaging software. A schematic of the instrument is illustrated in Fig. 1. All rock samples (which were pre-aged in crude oil for 24 h) were scanned before the contact angle measurements to obtain true RMS (root mean square) roughness values, which are presented in Table 3. While we note that commonly a sandpaper or diamond abrasive polish is used to render a rock surface smooth [44], we did not polish the samples in order to reflect measurements on original level of sample roughness as in subsurface conditions.

(instrument: ‘Ultima IV multipurpose x-ray diffraction systems’) and the results are tabulated in Table 3. It is notable that the samples exhibited a range of varying minerology from 100% calcite to 100% dolomite. Furthermore, it is interesting to note that the samples A and D are acquired from same formation (Arab-D), still they exhibit a distinct mineralogy. This is attributed to the highly heterogenous lithology of the Arab-D reservoir due to the dolomitization process [41,42]. Further, SEM-EDS images and spectra were acquired (using ‘Oxford instrument – JSM-6610’) to characterize the elemental composition and the pore morphology. Moreover, the porosity and permeability of these samples were measured using helium porosimeter and steady state gas

CCD Camera

Light Source

Interference Fringes

Beam Splitter

Computer program

Reference Mirror 2D & 3D Profiles

Rock Sample

Fig. 1. Schematic of Optical Profilometer Setup. 3

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Fig. 2. Experimental setting used for contact angle measurements, (a) brine (or water) manual injector (b) brine (or water) feed, (c) crude oil injector, (d) crude-oil feed, e) bulk-fluid (brine) storage, (f) drop-fluid (crude oil) storage, (g) High pressure high temperature (HPHT) cell, (h) needle dispensing a droplet of crude oil, (i) adjustable sample holder housed inside HPHT cell, (j) rock sample, (k) pressure and temperature display unit, (l) high-definition video camera, (m) light source, (n) image visualization and interpretation software.

Table 3 Mineralogical, petrophysical and surface properties of all samples used. Sample ID

Formation type

Mineralogy (XRD)

Elemental composition

Minerals

wt%

Element

wt%

C O Ca Mg C O Ca Mg Fe C O Ca Mg C O Ca Mg Fe C O Ca Mg Al

20.80 39.84 39.24 0.12 16.77 40.39 39.25 2.75 0.84 18.73 41.39 39.61 0.27 26.15 42.83 21.78 8.45 0.79 16.04 37.82 45.54 0.27 0.34

A

Arab-D carbonate

Calcite

100

B

Sulay Formation

Calcite Dolomite

61 39

C

Sulay Formation

Calcite

100

D

Arab-D carbonate

Dolomite

100

E

Pure calcite Iceland Spar

Calcite

100

Porosity(%)

Permeability(mD)

RMS Surface roughness(µm)

27.83

9844.3

49.675

29.52

13626.6

12.006

13.76

1.744

5.4

24.8

373.79

10.757

0–5*

Not measurable

0.301

* Typical porosity range for calcite (from Pedrosa et al. [43]).

highly biased θ measurements [45,46]. Subsequently, the rock samples were placed on the circular disc and housed inside the pressure cell, while temperature was raised to a desired value (298 K, 308 K, 323 K). The setup uses two mechanically operated pumps, namely the drop fluid and bulk fluid pumps (for crude oil and brine, respectively). The manual injector was first filled with crude oil, which was subsequently pumped into the drop-fluid storage. Next, the second injector was filled with brine, which was then pumped to fill the pressure cell and subsequently fill the bulk storage. A desired pressure was then applied by mechanical adjustment of the bulk-fluid piston and was left to stabilize. After pressure stabilization within the cell, a droplet of crude oil was dispensed onto the surface via a needle by a minute opening of the

2.4. Contact angle measurements Contact angle measurements were performed using a high-pressure high-temperature goniometric setup that uses a flat horizontal sample surface [note that such an equipment measures a contact angle value that is between the advancing and receding contact angles]. The schematic of the experimental setting is presented in Fig. 2. Rock samples were first cleaned with acetone and dried in an oven and were then aged in crude oil for 24 h at ambient condition. Note that surface cleaning is of key significance during contact angle measurements, and despite the debate on reliable surface cleaning methods, there is an agreement that contaminated rock surfaces can lead to 4

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160

Water Contact Angle [°]

120

80

Sample A (100% Calcite) Sample B (61% Calcite + 29% Dolomite)

40

Sample C (100% Calcite) Sample D (100% Dolomite) Sample E (Pure Calcite Mineral)

0

4

8

12

16

Operating Pressure [MPa] Fig. 3. Carbonate/crude-oil/brine contact angles measured as a function of operating pressure at 323 K.

valve of the drop-fluid pump. To allow the flow of a crude oil droplet into the aqueous phase, a pressure difference of 0.33 MPa (~50 psia) was created. The droplet was then allowed to rise onto the substrate and formed a contact angle at the three-phase contact line (the intersection of rock surface, crude oil and brine phases). The contact angles measured here are termed as ‘apparent’ contact angles. Notably, there is a rotating disk mechanism connected to the pressure cell that allows the rock sample surface to be rotated during the experiment. Such arrangement essentially allows formation of multiple droplets on the same sample surface within a single experiment. The contact angle (θ) formed on the rock surface was then monitored versus time (for approximately 45 min) and the most stable value was reported. Note that strictly speaking, a stable (Young’s) contact angle measurement is not possible; rather the measured apparent contact angle is a metastable value or ‘most stable contact angle’. This most stable contact angle value is the one that corresponds to the locally lowest Gibbs free energy state as pointed out by Marmur et al. [47] in an attempt towards the usage of more accurate contact angle related terminologies. While measuring highly reproducible contact angles is challenging, the error in reported measurements was ± 7° for θ measurements on rock core samples, and ± 3° on calcite mineral sample respectively. The additional complexity associated with rock core samples due to their porous surface, surface chemical heterogeneity and core cleaning is the

reason for the relatively higher error when compared to the proxy pure mineral surfaces. 3. Results and discussion Carbonate rocks demonstrate a variety of wettability characteristics ranging from water-wet to strongly oil-wet, including mixed-wet. This wetting behavior is further complicated by the variability of carbonate rock mineralogy, surface chemistry and rock surface roughness. In addition, operating conditions such as pressure and temperature influence the measured contact angle, too. To reduce the uncertainties associated with carbonate wetting measurements and to understand carbonate wettability variations, we measured water contact angles on five difference carbonate samples. The outcome of the study broadens the understanding of the factors influencing carbonate wettability. The subsequent subsections illustrate the results obtained. 3.1. Influence of pressure The impact of pressure on wettability of carbonate/crude-oil/brine systems was investigated by contact angle measurements for a range of pressures, i.e. 0.1 MPa, 7 MPa, and 15 MPa at a constant temperature (323 K). We identified two distinct trends of θ variation with pressure. For the pressure increment from ambient pressure to 7 MPa, a 5

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160

Water Contact Angle [°]

120

80

Sample A (100% Calcite) Sample B (61% Calcite + 29% Dolomite) Sample C (100% Calcite)

40

Sample D (100% Dolomite) Sample E (Pure Calcite Mineral)

295

300

305

310

315

320

325

Operating Temperature [K] Fig. 4. Carbonate/crude-oil/brine contact angles measured as a function of temperature at ambient pressure.

who measured θ for calcite/crude-oil/brine systems as a function of pressure. They found only a negligible effect of pressure on θ, suggesting a constant wettability regime versus pressure. The key difference, however, is that our measured θ values suggest a weakly waterwet calcite behavior as opposed to the strongly water-wet calcite surface observed by Seyyedi et al. [34]. The potential factors responsible for the discrepancy include different temperature (323 K vs. 310 K), brine chemistry (57670 vs. 54597 ppm) and composition as well as different physical and chemical properties of the crude oil used (Table 1). We highlight that the impact of pressure on θ in corresponding CO2 systems is more significant when compared to carbonate/crude-oil/ brine systems [4,48–50]. This can be attributed to a relatively larger density variation of CO2 with varying pressure (e.g. compare pressure dependence of crude oil density reported by Najafi-Marghmaleki et al. [37] vs. pressure dependence of CO2 density reported by Arif et al. [51]). This is an important observation since in situations where hydrocarbon oil was to be replaced by CO2 (e.g. in CO2 geo-sequestration in a depleted oil reservoir), the same carbonate rock will exhibit different wetting characteristics. Thus, it further reassures that wettability is not merely a function of rock type only. In fact, the intrinsic wettability is a function of rock/fluid interaction properties. In terms of implications, these results suggest that with natural pressure depletion, carbonate rocks tend to turn relatively less hydrophobic, while at higher pressures they are more hydrophobic. Increased hydrophobicity reduces residual oil saturation [52], which leads to a corresponding reduction in relative permeability. Note that it is well-

significant increase in θ was observed, while θ flattened with further pressure increase (Fig. 3). For instance, for sample A, θ increased from 114° to 138° when pressure increased from atmosphere to 7 MPa. However, when pressure was further increased to 15 MPa, θ measured 140°, indicating a negligible increase of 2° (within the experimental error). Similar results were found for sample B and D. These observations are consistent with Yang et al. [36] who found a notable influence of pressure on θ especially at lower temperature, e.g. θ increased from 100° to 138° when pressure increased from 0.1 MPa to 10 MPa at a fixed temperature of 300 K; however, θ flattened for any further pressure increase. At a higher temperature (i.e. 331 K) the effect of pressure on θ was, however, lower [36]. Moreover, Najafi-Marghmaleki et al. [37] found that the carbonate/crude-oil/brine θ increased from 72° to 77° at 333 K, implying only a minor change. While the trends of θ variation with are consistent with Najafi-Marghmaleki et al. [37], the absolute values of θ are much higher in this work. The results are also consistent with Zhang et al.’s [35] recent observations who found an increase in θ with increasing pressure for a carbonate rock sample (80% calcite + 18% dolomite). However, the calcite-rich carbonate core sample (sample C) and the pure calcite mineral (sample D) exhibited much different trends. θ increase with pressure followed a rather monotonic trend for sample C, e.g. for the pressure increment from 0.1 MPa to 7 MPa, θ increased from 85° to 97°, and θ increased to 110° when pressure further increased to 15 MPa (Fig. 3). The pure calcite sample, on the other hand, demonstrated a negligible effect of pressure on wettability. The influence of pressure on θ is consistent with the observations of Seyyedi et al. [34] 6

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Contact Angle [°]

120

80

40

0 Sam ple A

Sam ple B

Sam ple C

Sam ple D

Sam ple E

Carbonate sample

Fig. 5. Contact angles and wettability regimes measured for all samples at 15 MPa and 323 K.

function of temperature. Their reported Amott index increased from 0.40 to 0.64 when temperature increased from 343 K to 403 K, implying a wettability shift from intermediate-wet to weakly water-wet with temperature increase (note: an Amott index of 1 indicates strongly water-wet behavior and an Amott index of −1 indicates strongly oilwet behavior; [18]). Najafi-Marghmaleki et al. [37] found that two of their carbonate samples demonstrated a strong and clear increase in θ with increasing temperature, while the other two exhibited only a negligible effect. Notably, however, the mineralogy of these samples was not reported, which, strictly speaking, limits our current comparison. Furthermore, a decrease in θ with a corresponding increase in temperature is consistent with Lu et al.’s [40] recent observations. They measured contact angles for calcite/crude-oil/NaCl brine and calcite/crude-oil/MgCl2 brine systems as a function of temperature. They found that θ decreased from 130° to ~60° when temperature increased from 298 K to 338 K for 0.1 M aqueous NaCl solution, indicating a wettability alteration from weakly oil-wet to weakly water-wet, a significant shift in the wettability regime. Again, the slight differences in observed wetting behavior may be due in part to the differences in crude oil properties (compare this work vs. Lu et al. [40]; Table 1), or surface roughness. Moreover, Mwangi et al. [56] evaluated the wettability for limestone/n-decane/brine and dolomite/n-decane/brine systems. Their observations indicate that for the high salinity brine (salinity = 100,000 ppm), limestone wettability shifted towards more water-wet with temperature increase from 298 K to 383 K, while dolomite wettability first exhibited a small shift towards oil-wet for the temperature increment from 298 K to 343 K and then shifted towards water-wet again for the temperature increment from 343 K to 383 K.

established that oil recovery is higher in intermediate-wet rocks [53], since in water-wet rocks oil recovery is low due to trapped oil ganglia (compare Iglauer et al. [54]), while oil-wet rocks may experience lower recovery due to a pre-mature water breakthrough [53].

3.2. Influence of temperature In terms of the temperature effect on wettability, we found two distinct trends in measured datasets (Fig. 4). Specifically, carbonate rock samples A and C, and the pure calcite mineral exhibited a clear decrease in θ with increasing temperature. For instance, θ on carbonate sample C reduced from 110° to ~85° when temperature increased from 298 K to 323 K (Fig. 4), suggesting a notable decrease in hydrophobicity. Similar results were measured for the calcite mineral, e.g. for the temperature increment from 298 K to 323 K, θ reduced from ~70° to 60° suggesting a more hydrophilic calcite surface at higher temperature. However, the dolomitic carbonate samples (i.e. samples B and D) exhibited distinct behaviors. For example, θ demonstrated a monotonic increase with increasing temperature for Sample B, while for sample D the trend was non-monotonic, i.e. a decrease was followed by an increase (although this increase was within the experimental error). It is notable that the 100% calcite samples (sample A, C, and E) exhibited a decrease in θ with temperature, while the dolomitic samples demonstrated an increase in θ with temperature, still a clear generalization of the temperature effect on θ with respect to carbonate mineralogy cannot be reached and needs more investigation. Despite these complexities, the current findings are consistent with several independent observations. For instance, Kim and Kovscek [55] measured the Amott index of carbonate rock (oil-brine systems) as a 7

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0

1

0.2

Fig. 6. Ternary plot showing SEM-EDS elemental compositions of all samples; *theoretical calcite from Anthony et al. [59]. Note that the magnesium fraction of sample D (=0.0845, Table 2) is proportionally added into its oxygen, calcium and carbon fractions to ensure the sum of all entities in ternary scatter remains equal to 1.

0.8

0.4

0.6

0.6

0.4

0.8

0.2 Sample A (100% Calcite) Sample B (61% Calcite + 29% Dolomite) Sample C (100% Calcite) Sample D (100% Dolomite) Sample E (Calcite Mineral = 100% Calcite) Theoretical Pure Calcite*

1

0

0.2

0.4

0.6

0.8

0

1

Carbon (fraction)

mineralogy, crude oil composition and salinity differences can indeed lead to different interfacial mechanisms at the three-phase contact line, leading to differences in wettability.

However, they found these trends were different for different salinity conditions. The wettability alteration with temperature can be related to the interplay of the three interfacial tensions as depicted by the following force-balance:

γ − γsw A cosθ = so = t γow γow

3.3. Influence of minerology and surface chemistry In order to examine the influence of carbonate mineralogy on the wettability, contact angles were measured on four carbonate rock samples of varying mineralogy and a proxy calcite mineral as a benchmark at a constant pressure of 15 MPa and a temperature of 323 K (Fig. 5). Out of all the samples, the highest values of θ were observed for the dolomitic carbonate, i.e. θ = 156° for sample D (100% dolomite) (Fig. 5), implying that dolomite was strongly oil-wet at reservoir conditions. Sample A (100% calcite) was also found to be oil-wet (θ = 140°, Fig. 5); however, the degree of oil wetting was lower than that of sample D. Furthermore, samples B and C were somewhat weakly oil-wet to intermediate-wet as indicated by θ values of 129° and 110°, respectively. These results are somewhat consistent with Yang et al.’s [36] θ measurements on a limestone/crude-oil-/brine system where the measured θ was ~120° at similar pressure and temperature conditions (interpolated value at 15 MPa and 331 K). While the result is comparable, the slight differences may be attributed to the difference in temperature, surface roughness, reservoir brine composition, and crude oil properties (Table 1). Our observations are also somewhat consistent with Alhammadi et al. [24] who measured θ for carbonate/crude-oil/brine systems using three-dimensional micro-CT image analysis of the oil-filled rock sample at in-situ conditions (333 K and 10 MPa). For instance, the oil-filled pore spaces of the carbonate sample (96.5% calcite +1.5% dolomite) were found to be strongly oil-wet (θ = ~140°). However, they also observed a mixed-wettability behavior. For instance, the water-filled pore fractions were found to be water-wet (θ < 90°), while the oil-

(1)

In Eq. (1)), γso is the solid/oil interfacial tension, γsw is solid/water interfacial tension, and γow is the is the oil/water interfacial tension, and At refers to adhesion tension. Note that solid here refers to ‘rock’, and water refers to ‘brine’. Thus, the interplay of these three interfacial tensions as a function of temperature controls the contact angle and thus rock wettability (Arif et al. [51]). In this context, Arsalan et al. [57] recently determined the surface free energy of a Middle Eastern carbonate rock sample as a function of relative humidity (temperature) using inverse gas chromatography. Essentially, the Lifshitz–van der Waals, acidic and basic components were measured to compute the total surface free energy of carbonate rock. They found that the Lifshitz-van der Waals component of surface energy decreased with increasing temperature, while the acidic and basic components of surface energy increased with temperature [57]. Accordingly, two competing factors determine the total surface energy, while the acid/base interactions outweighed the Lifshitz-Van der Waals component. Further, from various other researches, it is known that high energy surfaces exhibit lower values of contact angles and vice versa [58]. Thus, these observations explain the reduction in contact angle with temperature for the calcite-dominant samples (samples A, C, and E). In a nutshell, our findings on the temperature effects and the insights from current literature suggest that temperature influences different types of carbonate rocks differently, and that the rock 8

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Fig. 7. Scanning Electron Microscopy images of a) Sample A, b) Sample B, c) Sample C, d) Sample D, e) Sample E.

filled pore spaces were found to be oil-wet (θ > 90°). Interestingly, the pure calcite mineral sample exhibited a remarkably different wetting regime and the measured θ was 62° at 15 MPa and 323 K (Fig. 5), implying a weakly water-wet calcite surface. This result is comparable with that of Seyyedi et al. [34] who found calcite to be strongly water-wet (interpolated θ = ~35°), while Zhang et al. [35] reported somewhat intermediate-wet calcite wettability at 15 MPa and 323 K (θ = 101°), implying a slight inconsistency. Nevertheless, this leads to another important finding that using pure calcite mineral as a proxy for carbonate rocks may not be fully justified owing to these differences in the observed wettability behavior. This is consistent with our recent published review [1], which critically analyzed the most-recent contact angle data repository for several important geological formations, where it was highlighted that using calcite as a proxy of limestone may be questionable. Thus, these results suggest that carbonates of varying mineralogy can indeed exhibit a variety of wettability regimes under the same

operating conditions. Furthermore, while samples A, C and E were all composed of 100% calcite, they displayed clearly different wetting regimes. This observation suggests that despite the sample mineralogy, rock samples can still demonstrate variable wetting behavior. We related this behavior to the elemental composition of these samples. A ternary scatter plot (Fig. 6) shows the elemental calcium, oxygen and carbon fractions of all samples, as well as the theoretical pure calcite mineral. Pure calcite (Sample E) is located at the highest position in the triangle relative to samples A and C and is characterized by the highest calcium and lowest carbon contents, which indicates a considerably different elemental composition. Note that the mineralogical differences between the pure calcite mineral used here and the theoretically pure calcite may be attributed to weathering and/or sample handling. In addition, sample D located far below in the triangle is characterized by lowest elemental calcium and highest carbon content relative to all other samples (due to Mg replacement of Ca in the dolomite). 9

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μm

a)

b)

c)

d)

e) Fig. 8. 2D surface topographic profiles of all samples: a) Sample A (RMS roughness = 49.675 µm), b) Sample B (RMS roughness = 12.006 µm), c) Sample C (RMS roughness = 5.4 µm), d) Sample D (RMS roughness = 10.757 µm), e) Sample E (RMS roughness = 0.301 µm).

to the Arab-D formation, while samples B and C are from the Sulay formation. Thus, despite belonging to the same formation, carbonates can still exhibit a wide wettability variation.

In principal, wetting is controlled by physisorption and chemisorption occurring at the carbonate surfaces. During physisorption, the stronger polar sites of the reservoir rock (i.e. strongly acidic Ca2+ sites and the strongly basic CO32– sites) are replaced by weakly polar sites of the water layer leading to a reduction of acidic and basic components of the rock surface energy [60]. During chemisorption, however, CaCO3 is decomposed to CaO, which then reacts with water to form isolated hydroxyl groups at the Ca2+ sites [57]. Thus, a higher calcium content will accelerate chemisorption and an increased formation of hydroxyl groups on the surface, which will lead to a more water-wet behavior (e.g. compare Abramov et al. [61]). Thus, such variations in elemental composition are responsible for this distinct wetting behavior. Other pertinent factors leading to different wetting behaviors of samples A, C and E, despite similar mineralogy i.e. 100% carbonate (although, strictly speaking they are not the same) are the sample porosity, pore structure, and surface roughness. For instance, Sample A is highly porous (~28% porosity, Table 3), while sample E (the pure calcite) is least porous. In addition, the SEM images (Fig. 7) indicate variable surface pore structure arrangements. Furthermore, it is worthwhile to note that samples A and D belong

3.4. Influence of surface roughness It is known from previous studies that surface roughness has a significant impact on contact angle on a real surface [62,63]. From a surface science perspective, a ‘real’ surface refers to a rough, non-isotropic and chemically heterogeneous surface as opposed to an ‘ideal’ surface which is homogenous, smooth and isotropic [47]. While the concept of surface roughness stems from the classical contributions such as Wenzel’s model [64] and Cassie’s model [65], the influence of roughness on rock wettability has not received much attention. We thus measured the RMS (root mean square) roughness of these rock samples and acquired the 2D and 3D surface height and topographic profiles (Figs. 8 and 9 respectively). It is interesting to note that these samples exhibit a range of surface roughness values. We found that the rock samples were much rougher than the pure mineral sample, which can be attributed to the porous nature of the rock and the weathering effects (note that the ‘black’ undetected regions in surface 10

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Fig. 9. 3D surface topographic profiles of all samples: a) Sample A (RMS roughness = 49.675 µm), b) Sample B (RMS roughness = 12.006 µm), c) Sample C (RMS roughness = 5.4 µm), d) Sample D (RMS roughness = 10.757 µm), e) Sample E (RMS roughness = 0.301 µm).

2D profiles are likely the ‘pores’ of the rock samples; Fig. 8). Out of all the samples tested, sample A was roughest with RMS of ~50 µm, while the calcite mineral surface (sample E) was smoothest with a RMS roughness of 0.301 µm. This is related to the 3D topographic profiles (Fig. 9), where it is notable that apart from the fresh calcite surface, all rock surfaces exhibit a range of peaks and valleys (note: ‘red’ indicates peaks, and ‘blue’ indicates valleys in Fig. 9). Such higher differences in the peaks and valleys give rise to higher surface roughness. Furthermore, the higher roughness values can also be attributed to adsorption of crude oil onto the rock surfaces. These observations are consistent with those of Seiedi et al. [66] who found that surface roughness values of the oil-wet mica samples were much higher than those of the fresh mica mineral surfaces. Further, crude oil might have adsorbed relatively more on sample A than all other samples which led to the higher roughness, and thus higher peak densities and non-uniformity as evident from the 3D profiles (Fig. 9). The smooth surfaces, on the contrary, have negligible asperities on the surface e.g. calcite surface (Sample E, Fig. 9). We note that a few studies reported lower RMS roughness of rock

samples e.g. Al-Yaseri et al.’s [49] dolomite sample had a roughness of 0.11 µm measured using atomic force microscopy (AFM). In principal, this difference appears to be due to the depth of investigation of the two instruments (micron-scale profilometer vs. sub-micron scale AFM). In order to further examine these relatively high surface roughness values, we acquired more magnified SEM images of all rocks samples (A through D, Fig. 10) which show that sample A surfaces are quite rough. Also, we note that since these samples were not treated (and not polished) and thus were naturally exposed to crude oil, which might have led to much rougher surfaces. We now relate these roughness profiles to the contact angle. Firstly, the abundance of the roughest surface asperities (i.e. red marked peaks as opposed to green and blue which are smoother) on Sample A and D might have contributed to the higher values of θ on these surfaces. Similarly, the lower θ values on Samples C and E may be related to the relatively lower proportions of roughest peaks on these surfaces (Fig. 9). There are studies which found that θ on a smoother surface is larger than the θ on the rougher version of the same surface if the surface is 11

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Fig. 10. Higher magnification SEM images of rock samples: a) Sample A, b) Sample B, c) Sample C, d) Sample D.

hydrophilic [49–51] or θ increases with increasing roughness for hydrophobic surfaces i.e. following the classical Wenzel model [64]. In the present case, however, on average it appears that θ increases with increase in RMS roughness irrespective of mineralogy and original wettability. In reality, however, each of these samples is unique due to different pore structure and mineralogy. Nevertheless, exploring the effect of varying surface roughness of the same type of sample on its contact angle is an area that needs further investigation.

mineral for carbonate rocks in contact angle studies is not fully justified. Furthermore, we found that contact angle variation is related to the elemental composition and surface roughness. It was found that rock samples exhibited relatively higher roughness compared to the pure mineral sample, and the surfaces with abundance of peaks demonstrated higher contact angles irrespective of mineralogy. Thus, it is important to take into account both the surface roughness and mineralogy of a sample for rock wettability characterization. In summary, out of the various influencing factors investigated here, temperature, mineralogy and rock surface roughness demonstrated a notable effect on carbonate wettability, while pressure had a relatively minor control. The measurements reported here thus provide insights into the factors influencing rock wettability and contribute towards the understanding of the wider variations associated with the wettability behavior of carbonate rocks.

4. Conclusions Wettability of reservoir rocks is a key physicochemical property which governs the fluid distribution in the pore spaces during primary depletion or enhanced oil recovery. Precise characterization of rock wettability is thus of immense significance for resource management and reservoir development decision making. In this context, an account of carbonate wettability is challenging due to associated complex pore structure. We thus measured carbonate/crude-oil/brine wettability of five different carbonate samples as a function of pressure, temperature, and a broad range of mineralogical and petrophysical properties. It was found that contact angle increased slightly with increasing pressure suggesting that the carbonate rock surfaces turns slightly more hydrophilic with pressure depletion. However, temperature had a much more significant effect on contact angle. For all 100% calcite samples, contact angle decreased with increasing temperature, while for dolomitic samples the mixed trends were found (e.g. a monotonic increase with temperature for sample B and a non-monotonic trend for sample D). Moreover, the influence of mineralogy on contact angle suggested that the dolomitic samples were relatively more hydrophobic compared to calcite-dominant samples and the pure calcite mineral was hydrophilic. This observation led us to conclude that using calcite as a proxy

Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

Acknowledgments Authors acknowledge King Fahd University of Petroleum & Minerals for the technical support for this publication. There were no competing financial interests during the execution of this work.

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