Functional Wettability in Carbonate Reservoirs - Energy & Fuels (ACS

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Functional Wettability in Carbonate Reservoirs Patrick V. Brady, and Geoffrey Thyne Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01895 • Publication Date (Web): 11 Oct 2016 Downloaded from http://pubs.acs.org on October 17, 2016

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Functional Wettability in Carbonate Reservoirs Patrick V. Brady1,* and Geoffrey Thyne2 1

Sandia National Laboratories, MS-0754, 1515 Eubank SE, Albuquerque, NM 87185-0754. 2

Engineered Salinity LLC, 1937 Harney Street, Suite 216, Laramie, WY 82072.

*To whom inquiries should be addressed: fax: 505-844-7354; email:[email protected].

Revised Version: September 29, 2016 Abstract Oil adsorbs to carbonate reservoirs indirectly through a relatively thick separating water layer, and directly to the surface through a relatively thin intervening water layer. While directly sorbed oil desorbs slowly and incompletely in response to changes in reservoir conditions, indirectly sorbed oil can be rapidly desorbed by changing the chemistry of the separating water layer. The additional recovery might be as much as 30% original oil in place (OOIP) above the ~ 30% OOIP recovered from carbonates due to reservoir de-pressurization (primary production) and viscous displacement (waterflooding). Electrostatic adhesive forces are the dominant control over carbonate reservoir wettability. A surface complexation model that quantifies electrostatic adhesion accurately predicts oil recovery trends for carbonates. The approach should therefore be useful for estimating initial wettability, and designing fluids that improve oil recovery. Introduction Wettability in petroleum engineering refers to the ease of oil and water movement in porous reservoir rocks. Standard wettability measurements include the Amott-Harvey and USBM methods that measure the relative flow of oil versus water in cores, as well as contact angles 1 ACS Paragon Plus Environment

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measured between liquids and mineral plates 1. Wettability depends on the balance of forces involved in mineral surface-fluid interactions and their effect on fluid movement 2. Three forces are in play at the molecular level: the van der Waals force, which is weakly attractive between 0.3 and 0.5 nm (intermolecular distance) becoming repulsive at shorter distances, the structural forces that represent the hydration or hydrogen bonding forces in the water layer, and the electrostatic force 3. These forces are chemical in nature and describe the adhesion between the surface and oil – which ultimately causes a resistance to flow. This is why contact angle, flotation, NMR, interfacial tension and capillary pressure measurements can be related to flowbased measurements. In the reservoir oil occurs in three forms, free phase, directly sorbed and indirectly sorbed. When oil adheres loosely to the reservoir surface, it probably does so through a 3-layer oil/water/rock configuration 4 – such as that shown in Figure 1a. This type of sorption is reversible and here termed indirect sorption. The degree of oil sorption depends on the separation distance between the oil and mineral, that is the thickness of the water layer, which itself depends on the net of the charges present at the two interfaces. The oil and mineral surface charges are themselves very sensitive to the composition of the water layer. Because water films are probably thicker than 8 nm under reservoir conditions 5, 6, the magnitude of the structural and electrostatic forces will usually exceed van der Waals forces.

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Figure 1. Indirect and direct sorption of oil on reservoir mineral surfaces. Oil can also adsorb directly to minerals and displace the water layer (Figure 1b). Direct adsorption of oil occurs if the attractive force is greater than the disjoining pressure 3, 7. We assume that directly sorbed oil is retained on mineral surfaces and can only be removed by the more heroic efforts of tertiary recovery - using CO2, surfactants, steaming and so on - since the bonds are stronger and there is no water layer to rapidly transmit wettability-altering chemicals to the oil and/or mineral surfaces 8. Incomplete, or extremely slow, desorption of ions and macromolecules from mineral surfaces occurs because directly sorbed species form much stronger anhydrous bonds by linking directly to high energy sites on mineral surfaces 9. These two types of sorption are the basis for contact angle hysteresis, the observation that the angle measured when the wetting fluid advances along a surface is greater than the angle when the fluid is receding along the same surface. A portion of the organic phase remains strongly adsorbed to mineral surfaces after initial contact, changing surface properties 8, 10. This change in the physical and chemical nature of the surface causes the hysteresis 11.


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Indirect and direct adhesion (sorption and adhesion are used interchangeably below) must be treated separately to construct a model for functional wettability. Defining functional wettability as the result of indirectly sorbed oil allows us to more clearly identify the causes of wettability alteration in carbonate rocks. We focus solely on indirectly sorbed oil which makes up the largest fraction of non-free phase OOIP, and which can be influenced by waterflooding. In reality, there will be a spectrum of configurations between the extremes of direct and indirect adhesion shown in Figures 1a and 1b. Separate is oil that is occluded in dead end pores or otherwise isolated from the flow system in the porous media. Recovery of Indirectly Sorbed Oil Laboratory and field waterfloods suggest that an additional 30% OOIP can be recovered over and above the ~30% OOIP that waterfloods recover from carbonates by viscous displacement, if the injection fluid chemistry is “right” (see below). Surface charge appears to be the key control over oil adhesion and wettability alteration that leads to improved recovery from carbonates 12-20. After filling with oil, reservoirs that were originally water-wet became oil-wet to water-wet depending on respectively greater or lesser oil adhesion to reservoir minerals. Oil recoveries are higher when the reservoir is water-wet (low adhesion); oil recoveries are lower when the reservoir is oil-wet (high adhesion), all other things being equal. But it is not clear why, for example, one reservoir is oil-wet while another is water-wet. Nor can the “right” waterflood chemistry be predicted which will maximize production from a particular reservoir. Several key trends have been identified though. Table 1 lists experiments in which reservoir carbonate cores showed increasing recovery due to changes in water chemistry, typically ascribed to achieving more water-wet conditions. Early work with chalk showed that lower salinity and/or increased Ca2+, Mg2+ and SO42- increase 4 ACS Paragon Plus Environment

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recovery by changing the surface charge, and wettability, of carbonate minerals 21-26. Many of the early analyses simply compared seawater vs. produced water impacts on recovery. Later experiments considered the specific effects of temperature, water composition, salinity, and rock composition on recovery. A complicating factor is that salinity was changed by diluting either seawater (or formation water) which simultaneously reduced the concentrations of the divalent ions, making salinity- and divalent-specific effects on oil recovery hard to separate. In some cases, cores contained anhydrite and/or pyrite which, because they are sources of dissolved sulfate, can obscure the link between injectate sulfate concentration and wettability. Romanuka et al. 27 reported a wide range of incremental recoveries upon dilution from limestone and dolomite, but two of the limestones and both dolomites contained anhydrite or pyrite. Yousef et al. 28 found increased recovery at 20-fold dilution using cores containing about 6% anhydrite. Shariatpanahi et al. 29 tested dilution on limestone cores with anhydrite and observed 13% OOIP increased recovery with 30-fold dilution. Pu et al. 30 tested dolomite cores that contained anhydrite and found an additional recovery of 5.5 to 8.1% OOIP at 60°C, but Jiang et al. 31 used cores from the same formation with ten-fold dilution and saw no incremental recovery at 45°C. Austad et al. 12 used chalk and limestone cores to test dilution effects on recovery, but found only cores with anhydrite responded to dilution, concluding that sulfate may be required for the dilution effect. Zahid et al. 32 used anhydrite-free limestone reservoir cores and showed increased recovery up to 19% OOIP at 90°C, with most of the recovery achieved at 10-fold dilution. Increasing dilution beyond this level did not significantly increase recovery. This agrees with Alameri et al. 33 who used Middle Eastern carbonate cores and observed incremental production using brine with NaCl removed to lower salinity. Romanuka et al. 27 and Fathi et al. 5 ACS Paragon Plus Environment

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performed imbibition experiments with the Stevns chalk and showed that lowering ionic

strength increased production. Al-Attar et al. 34 found that reducing salinity increased production and water-wettness in reservoir cores composed of calcite and dolomite. Lowering salinity by 40-50 fold increased production by about 20% OOIP, but further dilution had little effect. Shaikh and Sharifi 35 found lowering salinity in limestone by a factor of 3.5 times increased recovery by 12-18% by shifting wettability from oil-wet to water-wet. Awolayo et al. 20 used anhydrite-free limestone cores and found both salinity reduction and sulfate enrichment individually improved recovery in corefloods. A 6-fold dilution produced 5.7 to 6.5% OOIP improved recovery, while increasing sulfate up to eight-fold improved recovery by about 7.5% OOIP. Wettability measurements showed improved recovery was related to more water-wet conditions. Nasralla et al. 36 used limestone reservoir cores without anhydrite and found fivefold dilution increased recovery by 3 to 4% OOIP, but further dilution did not increase recovery. Shariatpanahi et al. 18 showed no additional oil recovery from dolomite core plugs using seawater, but a 15% increase in recovery with diluted seawater.


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Table 1. Measured incremental oil production from water chemical changes in carbonates. Rock Calcite Calcite

Variable -2

SO4 SO4-2 -2

Calcite

SO4

Calcite

SO4-2 -2

% OOIP

dil/add

Temp °C

Method

11

3X

110

IMB

2

2-3X

90

CF

26

4X

70

IMB

22

4X

100

IMB

5

4X

130

IMB

Calcite

SO4

Calcite

Mg+2, SO4-2

2

4X

70

IMB

Calcite

Mg+2, SO4-2

21

4X

100

IMB

Calcite

Mg+2, SO4-2

32

4X

130

IMB

Dolomite/Anhydrite

dil.

5.5 to 8.1

20X

60

IMB/CF

Calcite/Dolomite/Anhydrite

dil.

19

10X

100

CF

Calcite/Anhydrite

7 to 10

5X

110

IMB

Dolomite

dil. and SO4-2 SO4-2

6

4X

100

CF

Dolomite

SO4-2

9

4X

100

CF

5.1

4X

121

CF

-2

Calcite

SO4

Calcite

borate

15.6

121

CF

Calcite

phosphate

21.3

121

CF

Calcite

dil. and SO4-2

up to 5

2-4X

130

IMB

Calcite

dil. and SO4-2

up to 15

2-4X

130

IMB

none

2-4X

130

IMB

Calcite/Pyrite

dil. and SO4-2

Calcite

dil.

2 to 4

2 - 6X

100

IMB

Calcite

dil. and SO4-2

up to 30

2-6X

70 - 120

IMB

Calcite

dil. and SO4-2

19

2X

90

IMB

Calcite

9

6X

90

IMB

Calcite

dil. SO4-2

15

4X

90

IMB

Calcite

SO4-2

20

4X

100

IMB

15

4X

120

IMB

-2

Calcite

SO4

Calcite

SO4-2

5 to 10

range

60

IMB

Calcite/Pyrite

dil. and SO4-

0 to 4

range

70

IMB

Calcite/Dolomite/Pyrite

dil. and SO4-2

3 to 4

range

70

IMB

Calcite/Dolomite/Pyrite

dil. and SO4-2

9 to 15

range

120

IMB

Calcite

dil. and SO4-2

13 to 21

30X

70

IMB

Dolomite/Anhydrite

dil. and SO4-2

5 to 18

53X

85

IMB

Dolomite/Pyrite

dil. and SO4-2

9 to 14

60X

70

IMB

Limestone

dil.

1.4

20X

22

CF

Limestone

dil.

19

20X

90

CF

chalk

dil.

0.59

10X

90

CF

Calcite

dil.

4

5X

120

CF

Calcite

dil.

3 to 4%

5X

70

CF

Calcite/Dolomite

dil.

8

4X

20 and 90

CF

Calcite

dil. and SO4-2

up to 14

6-8X

110

CF

Source 37 38 21 21 21 23 23 23 30 39 29 40 40 40 40 40 41 41 41 41 41 41 41 41 41 41 27 27 27 27 27 27 27 32 32 32 36 36 33 20

dil = dilution. add = addition. Dol = dolomite. Py = Pyrite. Kaol = Kaolinite. IMB = imbibition. CF = core flood. Note in some cases dilution was from changing initial brine to seawater, see original references for details.


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Fathi et al. 14 were able to separate the effects of dilution from sulfate (see Figure 2). The authors showed that lowering salinity by a factor of two increased production by 21% OOIP, and further lowering salinity another three-fold (by removing NaCl) yielded another 11% OOIP. Zahid et al. 32 saw no effect of dilution on recovery from Aalborg chalk outcrop cores suggesting that not all carbonate rocks respond positively to lowered salinity.

Figure 2. Experimental results from imbibition experiments on chalk cores at 90°C. VB = saline formation water; SW = seawater; SW0NaCl = seawater depleted in NaCl; SW0NaCl-4SO4 = seawater depleted in NaCl but with 4 times the sulfate of seawater (figure modified from Fathi et al. 14). Many experiments show increased production from increasing anion concentrations, specifically sulfate. Fathi et al. 14 reported increases in recovery of 20% OOIP by increasing sulfate levels of


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the imbibing fluid for chalk cores. Al-Attar et al. (2013) showed increasing sulfate four-fold, even at room temperature, produced more oil, but additional sulfate did not. Gupta et al. 40 showed that substituting borate and phosphate for sulfate during core floods increased recovery in anhydrite-free carbonate cores by 15.6% and 21.3% OOIP, respectively. But not all experiments showed improved production. Fernø et al. 41 measured the effect of sulfate on 3 chalks - Rørdal, Niobrara, and Stevns - at 130°C; sulfate only increased recovery from the Stevns chalk. The observations cited above can be generalized: 1. Low salinity, i.e. dilution, can increase recovery, but there is a limit beyond which increasing dilution does not increase recovery; 2. Sulfate, phosphate, and borate can increase recovery; 3. Recoveries appear to differ between chalk, limestone, and dolomite for similar conditions; 4. Effluent pH typically increases during reaction with more dilute solutions31, 34, 42. 5. The increase in oil recovery is rapid, occurring in 1-2 pore volumes and reaching a plateau, similar to the response seen in ion exchange columns. A predictive model of wettability alteration in carbonates must be able to explain how the common features identified above link to oil and mineral surface charge modification by water chemistry changes. Carbonate surfaces have both cation and anion exchange sites. Oil has cationic surface groups, -NH+ and –COOCa+, that coordinate to the carbonate cation exchange sites, and anionic –COO- surface groups that coordinate to carbonate anion exchange sites; both hold the larger oil macro-molecule in place. Flushing the reservoir with a solution that decreases the number of these electrostatic bridges desorbs the oil enabling its movement through the 9 ACS Paragon Plus Environment

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reservoir. Precisely designing wettability-modifying solutions requires a numerical model of both calcite and oil surface charge 43. Calcite Surface Charge A carbonate surface is made up of hydrated calcium and carbonate sites, denoted respectively as >CaOH and >CO3H. Carbonates develop surface charge by these sites gaining or losing H+s (surface acid-base reactions), and by subsequent adsorption of multi-valent cations or anions on the now-charged sites. For example, above pH 5 surface carbonate groups lose H+ and become negatively charged. This negative charge can be reversed if enough Ca+2 is sorbed from solution onto the negatively charged carbonate groups. The net mineral surface charge is the sum of the individual surface species’ concentrations. Above the charged mineral surface is a layer of hydrated counter-ions that balance the surface charge; for example Na+ typically coordinates above negatively charged surface sites, Cl- above positively charged sites. The counter-ions are only loosely associated with charged surface sites because of the accompanying water molecules and are otherwise assumed to possess no specific affinity for surfaces. The surface charge + counter-ions + associated water at the mineral-water interface is called the electric double layer. An electric double layer also exists at the oil-water interface, the only differences being that: 1. the oil-water interface is more flexible than the crystalline mineral-water interface; and 2. the oil-water interface will have more polar groups exposed at the surface compared to the interior. Traditionally, petroleum engineers have inferred mineral and oil surface charge by measuring zeta potentials, in volts. While this approach can qualitatively constrain surface mechanisms, in order to quantitatively describe individual surface reactions, or to tailor injectates for a particular reservoir, surface reactions must be described in


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units of moles. We do this below by developing surface complexation models of the oil and carbonate interfaces. The calcite isoelectric point (IEP) occurs at pCa ~ 3.5 - 4.5 and the PCO2 = 10-3.5 atm; the pHiep is near 8.2 with considerable variation. Increased Ca2+ adsorption increases calcite surface charge; increased CO32- adsorption decreases calcite surface charge. Sulfate adsorption decreases calcite surface charge, particularly near the IEP 44. Figure 3 shows the pH (PCO2) dependence of calculated calcite surface charge and speciation in water at 100oC. The system was set to calcite saturation and the PCO2 varied from 10 atm to 0.001 atm to vary solution pH from, respectively, 5.3 to 7.9. PHREEQC version 2.15.06 45 was used to simulate the calcite surface charge in Figure 3 using as input the calcite complexation constants of Pokrovsky et al. 46 and Van Cappellen et al. 47; also see Hiorth et al. 48. >CaOH + H+ ↔ >CaOH 2+

K1 = [>CaOH2]exp(Fψ/RT)/[ >CaOH]{H+} = 1011.85

>CaOH + HCO3- ↔ >CaCO3- + H2O >CaOH2+ + SO4-2 ↔ >CaSO4- + H2O >CO3H ↔ >CO3- + H+

[1]

K2 = [>CaCO3-]exp(-Fψ/RT)/{HCO3-}[>CaOH] = 105.8

[2]

K3 = [>CaSO4-]exp(-2Fψ/RT)/{SO4-2} [>CaOH2+] = 102.1

[3]

K4 = [>CO3-]exp(-Fψ/RT)/[ >CO3H]{H+} = 10-5.1

[4]

>CO3H + Ca+2 ↔ >CO3Ca+ + H+

K5 = [>CO3Ca+]exp(Fψ/RT){H+}/[>CO3H]{Ca+2} = 10-2.6 [5]

>CO3H + Mg+2 ↔ >CO3Mg+ + H+

K5 = [>CO3Mg+]exp(Fψ/RT){H+}/[>CO3H]{Mg+2} = 10-2.6 [6]

[ ]’s are concentrations (mol/M2). {}’s denote thermodynamic activities. Equilibrium intrinsic Ks for the reactions above are modified with a surface electrostatics term, exp(zFψ/RT); where z is the absolute change in surface charge with reaction, F is Faraday’s constant; ψ is the surface potential; R is the gas constant; and T is absolute temperature. A diffuse layer model of the electric double layer is used here because it is the most basic of double layer models; it requires 11 ACS Paragon Plus Environment

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no adjustable parameters other than the surface log Ks. The calculation in Figure 3 assumes that reservoir fluids simultaneously maintain chemical equilibrium with the surface and with the dissolving/reprecipitating carbonate mineral.

Figure 3. Calculated calcite surface speciation and charge in 0.1M NaCl at 100oC.

Oil Surface Charge Total oil acid and base numbers, TAN and TBN, are thought to be proxies for the number of carboxylic acid and nitrogen base groups present at the oil-water interface 4, 49. TAN and TBN units are mg KOH/g oil. Oil with high TBN/TAN values will have a relatively high pH of zero surface charge; a low TBN/TAN oil will have a more negative surface charge at a given pH than a high TBN/TAN oil. Figure 4 shows a range of total acid and total base numbers reported in the


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literature. Oil bases tend to outnumber oil acids, and concentrations range from 10’s to 1000’s of parts per million (mg/kg).

Figure 4. Compilation of reported total acid and acid/base numbers (TAN and TBN) for crude oils. Figure 5 shows calculated 100oC oil surface chemistry as a function of pH and NaCl concentration for an oil with BN/AN = 10. Figure 5 was constructed using PHREEQC, a diffuse layer model, and the (25oC) reactions below from Brady and Krumhansl 13.

-NH + H+ ↔ -NH 2+ -COOH ↔ -COO- + H+ COOH + Ca+2 ↔ -COOCa+ + H+

K1 = [-NH 2+]exp(Fψ/RT)/[ -NH]{H+} = 10-6

[7]

K4 = [-COOH]exp(-Fψ/RT)/[ -COO-]{H+} = 10-5

[8]

K5 = [-COOCa+]exp(Fψ/RT){H+}/[-COO-]{Ca+2} = 10-3.8

[9]


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Figure 5. Oil surface species concentrations as a function of pH calculated with a surface complexation model of the oil-water interface in three NaCl + 10 mM CaCl2 solutions. Black lines = -NH+; red lines = -COOCa+; blue lines = -COO-.

Oil-Calcite Adhesion The calculations in Figures 3 and 5 identify the primary charged species present on oil and calcite surfaces which are those most likely to control indirect electrostatic adhesion. Figure 6 shows the most likely potential linkages between calcite surface groups and oil surface groups. Oil –COO- groups can coordinate to calcite >CO3Ca+ and >CaOH2+ groups; oil –NH+ and – COOCa+ groups can coordinate to calcite >COO- and >CaSO4- groups. Figure 7 shows the dependence of calcite-oil attraction, i.e. calculated calcite-oil bond products, on pH (PCO2).


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Figure 6. Potential electrostatic linkages between calcite and oil.


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Figure 7. Bond products for oil-calcite electrostatic pairs. 0.01M NaCl in equilibrium with calcite. Oil BN/AN = 10.

The bond product is a measure of the amount of oil-mineral electrostatic attraction and is the summed products of the surface concentrations of oppositely charged species on oil and mineral surfaces 13. If oil and rock surfaces only contained like-charged species, the bond product would equal zero because no oppositely charged surface groups exist; adhesion would be unlikely except by dipole-surface interactions. If the oil and rock only contained oppositely charged surface species, the bond product would be high, and the potential for oil-mineral adhesion at contact points would be high. Figure 7 shows that linking between oil nitrogen bases and calcite >CO3- groups dominates oil-calcite electrostatic attraction at low pH (high PCO2), the [-


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NH+][>CO3-] bridge in Figure 6. At higher pH (lower PCO2), the [-COO-][>CaOH2+] bridge dominates oil-calcite electrostatic adhesion.

The picture shown in Figure 7 is more complicated under reservoir conditions because of the presence of other potential-determining ions, in particular, Mg+2 and SO4-2. Adsorption of Mg+2 to >CO3- or >CaCO3- sites will increase surface charge; adsorption of SO4-2 to >CaOH2+ or >CO3Ca+ sites will decrease surface charge. Both will affect the adhesion of oil by changing the balance of electrostatic forces operating between the mineral and oil surfaces. For example, Figure 8 shows the effect of sulfate on oil-calcite adhesion as a function of pH at 100oC, and identifies the primary oil:calcite electrostatic pairs. Figure 8 suggests that above pH 6 sulfate will decrease oil adhesion and increase recovery by sorbing to, and decreasing the number of, >CaOH2+ sites.


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Figure 8. Bond product sum for oil-calcite electrostatic pairs in seawater (SW) and Seawater + 4xSO4 in equilibrium with calcite at 100oC; Oil BN/AN = 10.

Quantifying the complex system of equations for a reservoir is facilitated by the use of geochemical models.

Controls on Reservoir Bulk Fluid Chemistry The final input needed to apply the electrostatic analysis to a particular reservoir is a geochemical model of the fluid-rock reactions that control for example the pH, salinity, and 18 ACS Paragon Plus Environment

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hardness of the connate and the waterflood. This primarily involves identifying what minerals and gases will be at equilibrium with the connate fluid under the temperature and pressure conditions of the reservoir. Reservoir pH ranges from 5 to 6.5 and is controlled by either carbonate or feldspar-clay equilibrium depending on temperature and reservoir mineralogy 50. Note that this sort of geochemical modeling is already routinely done in many reservoirs see e.g. 51

to assess, for example, the potential for scale formation. Here the goal is to constrain the

chemistry of the thin film separating indirectly sorbed oil from the mineral surfaces. The reservoir system, including the adhering oil, will react depending on the degree of disequilibrium by connate-waterflood mixing, dissolution, precipitation, desorption, sorption, and cation exchange reactions. While carbonate dissolution will sharply limit, for example, Ca+2 and HCO3levels of the injectate in the reservoir 52, thin-film salinity will be less affected by mineraldissolution reactions. Surface reactions will have a stronger impact on dissolved sulfate levels in the absence of reservoir anhydrite, and on dissolved Mg+2 levels in the absence of reservoir dolomite. Reservoir Prediction The reservoir geochemical analysis described above defines the initial fluid chemistry, the waterflood fluid chemistry, and what minerals/gases the rocks react with before and during waterflooding. These constraints are used as inputs to a reaction-path model such as GWB 51 or PHREEQC 45. The surface complexation model is run simultaneously to calculate surface charge on oil and carbonate surfaces as the waterflood is computationally “reacted” with a column of reservoir material. Figure 9 shows a theoretical prediction of oil-calcite adhesion at 100oC when progressively lower salinity fluids are pushed through a reservoir. The initial salinity is 213,380 mg/l. The BN/AN of the oil was set to 10. Table 2 shows the connate 19 ACS Paragon Plus Environment

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waterflood compositions. The oil-calcite assemblage is first equilibrated with the saline connate brine, then equilibrated sequentially with 10 pore volumes of seawater, 6 pore volumes of halfdiluted seawater, 3 pore volumes of 10-fold diluted seawater, and 4 pore volumes of 100-fold diluted seawater. The calculation assumes 20% porosity, 90% of which is filled with water, 10% with residual oil. The input solution was equilibrated with 0.01 atm CO2 and during transport the solution maintains equilibrium with anhydrite, calcite, and dolomite. Increased recovery from a carbonate with decreasing water salinity is typically observed 14, 32, 33, 39

. But the multiple competing reactions have made the specific mechanisms involved difficult

to quantify. Figure 9 shows that decreased salinity decreases the calculated oil-calcite bond product sum, that is it decreases oil adhesion and increases oil recovery – consistent with observations. Moreover, Figure 10 shows quantitatively which reactions control the carbonate low salinity effect – namely decreased sulfate levels and an increase in pH in low salinity solutions causing a decrease in the number of [>CaSO4-][-NH+] and [>CaSO4-][-COOCa:Mg+] pairs and an increase in recovery. The initial conditions are at equilibrium with calcite. Lowering the salinity caused dissolution of calcite increasing the pH 52. There is a slight separate, non-sulfate low salinity effect in that decreased salinity causes a decrease in oil and calcite surface species concentrations which prompts additional oil recovery – but it is less than the sulfate effect in this example. Figure 10 diluting seawater more than a factor of 10 leads to diminishing returns, consistent with the coreflood observations of Yousef et al. 39. Because the electrostatic approach lends itself to quantitatively interpreting coreflood results it should allow optimizing field-specific waterflood recipes and volumes to achieve maximal recoveries. It should be emphasized that the calculations in Figures 8, 9, and 10 involved no fitting to coreflood results.


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Figure 9. Theoretical prediction of oil-calcite adhesion at 100oC as a function of waterflood composition. SW = seawater. The examples in Figures 8 and 9 reproduce, and explain predictively, the key common observations from the literature, namely: 1. Low salinity, i.e. dilution, increases recovery, but there is a limit beyond which increasing dilution does not increase recovery (Figure 9); 2. Sulfate increases recovery (Figure 8); 3. Effluent pH typically increases during reaction with more dilute solutions (Figure 9); 4. The increase in oil recovery is rapid, occurring in 1-2 pore volumes and reaching a plateau, similar to the response seen in ion exchange columns (Figure 9). The fact that recoveries differ between chalk, limestone, and dolomite for similar conditions is likely due to surface area differences between the minerals. The surface area of calcite and dolomite is dependent on crystal size and varies between reservoirs. Chalk is biogenic in origin 21 ACS Paragon Plus Environment

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and retains the complex surface structures compared to calcite and dolomite. This leads to higher chalk surface area compared to other carbonate crystals 53. Table 2. Fluid compositions for calculation in Figure 9 (all in mg/L). Connate SW Ca 19040 650 Mg 2439 2110 SO4 350 4290 Na 59491 18300 Cl 132060 32200 after Yousef et al. 39.

Figure 10. Individual bond products for the Figure 9 calculation. Water wetness increases with sulfate concentration because, all other things being equal, sulfate will sorb onto, and locally reverse the charge on, calcite >CaOH2+ groups to decrease oil adhesion 13. Boron sorbs to calcite 54; maximum sorption is at pH 9.5 at 25oC; sorption decreases at lower and higher pHs. The likely boron sorption mechanism is borate ion, B(OH)4-, linking with calcite surface >CaOH2+ groups. Increased dissolved boron will therefore locally decrease the charge on calcite >CaOH2+ groups to decrease adhesion through [>CaOH2+][-COO-] bridges. 22 ACS Paragon Plus Environment

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The greatest effect will be at higher pHs. Phosphate exists at H2PO4- below pH ~ 7 at 25oC, and as HPO4-2 at higher pH, and is known to electrostatically sorb to calcite surfaces 55. At relatively high phosphate concentrations (>130 µM) calcium phosphate mineral(s) precipitate on the calcite surface. Relatively low concentrations of phosphate (CaOH2+ sites. This would have the effect of decreasing oil adhesion by eliminating the >CaOH2+ sites that would otherwise form [>CaOH2+][-COO-] bridges. Conclusions An independently-derived diffuse layer model quantitatively explains the pH shift, plateau of incremental oil production, and oxyanion role in increased oil recovery from carbonates observed in corefloods. The approach might therefore be used to design injection waters that maximize oil recovery. Acknowledgements PVB appreciates funding from Sandia National Laboratories. Sandia is a multiprogram laboratory operated by Sandia Corporation, a Lockheed Martin Company, for the United States Department of Energy’s National Nuclear Security Administration under contract DEAC0494AL85000. References


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34. Al-Attar, H. H.; Mahmoud, M. Y.; Zekri, A. Y.; Almehaideb, R.; Ghannam, M., Lowsalinity flooding in a selected carbonate reservoir: experimental approach. Journal of Petroleum Exploration and Production Technology 2013, 3, (2), 139-149. 35. Shaikh, M.; Sharifi, M. In Investigation of optimum salinity of injected water in carbonate reservoirs using wettability measurement and core flooding, SPE Reservoir Characterization and Simulation Conference and Exhibition, 2013; Society of Petroleum Engineers: 2013. 36. Nasralla, R. A.; Sergienko, E.; Masalmeh, S. K.; van der Linde, H. A.; Brussee, N. J.; Mahani, H.; Suijkerbuijk, B.; Alqarshubi, I. In Demonstrating the potential of low-salinity waterflood to improve oil recovery in carbonate reservoirs by qualitative coreflood, Abu Dhabi International Petroleum Exhibition and Conference, 2014; Society of Petroleum Engineers: 2014. 37. Strand, S.; Hognesen, E. J.; Austad, T., Wettability alteration of carbonates: effects of potential determining ions (Ca2+ and SO42-). Colloids Surface A. 2006, 275, 1-10. 38. Webb, K. J.; Black, C. J. J.; Tjetland, G. In A laboratory study investigating methods for improving oil recovery in carbonates, International Petroleum Technology Conference, 2005; International Petroleum Technology Conference: 2005. 39. Yousef, A. A.; Al-Saleh, S.; Al-Kaabi, A. U.; Al-Jawfi, M. S. In Laboratory investigation of novel oil recovery method for carbonate reservoirs, Canadian Unconventional Resources and International Petroleum Conference, 2010; Society of Petroleum Engineers: 2010. 40. Gupta, R.; Smith, G. G.; Hu, L.; Willingham, T.; Lo Cascio, M.; Shyeh, J. J.; Harris, C. R. In Enhanced Waterflood for Carbonate Reservoirs-Impact of Injection Water Composition, SPE Middle East Oil and Gas Show and Conference, 2011; Society of Petroleum Engineers: 2011. 41. Fernø, M. A.; Grønsdal, R.; Åsheim, J.; Nyheim, A.; Berge, M.; Graue, A., Use of Sulfate for Water Based Enhanced Oil Recovery during Spontaneous Imbibition in Chalk. Energy & Fuels 2011, 25, 1697-1706. 42. Gandomkar, A.; Rahimpour, M. R., Investigation of Low-Salinity Waterflooding in Secondary and Tertiary Enhanced Oil Recovery in Limestone Reservoirs. Energy & Fuels 2015, 29, (12), 7781-7792. 43. Brady, P. V.; Krumhansl, J. L. Waterflooding injectate design systems and methods, . US Patent 8,812,271, 2014. 44. Pierre, A.; Lamarche, J. M.; Mercier, R.; Foissy, A.; Persello, J., Calcium as potential determining ion in aqueous calcite suspensions. J. Dispersion Science and Technology 1990, 11, (6), 611-635. 45. Parkhurst, D. L.; Appelo, C. A. J., User's guide to PHREEQC (Version 2) - A computer program for speciation, batch-reaction, one-dimensional transport, and inverse geochemical calculations. Water-Resources Investigations Report 99-4259. In U.S. GEOLOGICAL SURVEY, Ed. Reston, VA, 1999. 46. Pokrovsky, O. S.; Schott, J.; Thomas, F., Dolomite surface speciation and reactivity in aquatic systems. Geochem. Cosmochim. Acta. 1999, 63, 3133-3143. 47. Van Cappellen, P.; Charlet, L.; Stumm, W.; Wersin, P., A surface complexation model of the carbonate mineral-aqueous solution interface. Geochim. Cosmochim. Acta. 1993, 57, 35053518. 48. Hiorth, A.; Cathles, L. M.; Madland, M. V., The impact of pore water chemistry on carbonate surface charge and oil wettability. Transport in Porous Media 2010.


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49. Dubey, S. T.; Doe, P. H., Base number and wetting properties of crude oils. SPE Reservoir Engineering 1993, August, 195-199. 50. Thyne, G.; Brady, P., Evaluation of Formation Water Chemistry: Bakken Shale. Journal of Petroleum Science and Engineering (in press). 2016. 51. Bethke, C.; Yeakel, S., The Geochemist’s Workbench (Version 9.0): Reaction modeling guide. Aqueous Solutions, LLC, Champaign, Ill 2012, 96p. 52. Yutkin, M. P.; Lee, J. Y.; Mishra, H.; Radke, C. J.; Patzek, T. W. In Bulk and Surface Aqueous Speciation of Calcite: Implications for Low-Salinity Waterflooding of Carbonate Reservoirs, SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition, 2016; Society of Petroleum Engineers: 2016. 53. Walter, L. M.; Morse, J. W., Reactive surface area of skeletal carbonates during dissolution: effect of grain size. Journal of Sedimentary Research 1984, 54, (4). 54. Goldberg, S.; Forster, H., Boron sorption on calcareous soils and reference calcites. Soil Science 1991, 152, (4), 304-310. 55. Sø, H. U.; Postma, D.; Jakobsen, R.; Larsen, F., Sorption of phosphate onto calcite; results from batch experiments and surface complexation modeling. Geochimica et Cosmochimica Acta 2011, 75, (10), 2911-2923.


Functional Wettability in Carbonate Reservoirs - Energy & Fuels (ACS

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