Wettability Alteration and Improved Oil Recovery in Chalk: The Effect

Sep 6, 2006 - It was previously documented that seawater was able to change the wettability of oil-saturated chalk toward more water-wet conditions an...
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Wettability Alteration and Improved Oil Recovery in Chalk: The Effect of Calcium in the Presence of Sulfate Peimao Zhang,* Medad T. Tweheyo, and Tor Austad UniVersity of StaVanger, 4036 StaVanger, Norway ReceiVed February 23, 2006. ReVised Manuscript ReceiVed August 1, 2006

It was previously documented that seawater was able to change the wettability of oil-saturated chalk toward more water-wet conditions and that enhanced spontaneous imbibition of water was observed. The efficiency of the imbibition process was improved by increasing the sulfate concentration in seawater. Both calcium and sulfate present in seawater are potential determining ions toward the chalk surface; it is therefore expected that both of the ions are involved in the wettability modifying process, and the symbiotic effects between the ions are studied in this paper with the aim of improving oil recovery from moderate water-wet chalk. Outcrop chalk samples were aged at 90 °C in an acidic crude oil for at least 4 weeks. The concentration of Ca2+ was varied both in the imbibing seawater and in the initial brine. Chromatographic wettability tests showed that the initial wetting condition of the chalk was not significantly affected by changing the concentration of Ca2+ in the initial brine. Increased oil recovery by spontaneous imbibition was observed with increasing concentration of Ca2+ in the imbibing seawater or increasing concentration of Ca2+ in the initial brine. The imbibition increased as the temperature increased, but care must be taken to avoid precipitation of CaSO4(s) at high temperatures. The spontaneous imbibition tests confirmed that SO42- and Ca2+ played an important role in the wettability modifying process. A chemical mechanism for the wettability alteration was suggested to involve the coadsorption of SO42- and Ca2+ onto the chalk surface, which resulted in desorption of carboxylic material.

1. Introduction Water flooding of naturally fractured low permeable carbonates is usually not successful because of low water wetness and small or negative capillary forces, which prevent spontaneous imbibition of water from the fractures into the matrix blocks.1,2 The reason most of the carbonate oil reservoirs act as neutral or preferential oil-wet has been discussed in details by Hiraski and Zhang.3 The oil-water interface becomes negatively charged because of dissociation of carboxylic material, whereas the rock-water interface becomes positively charged because of the high concentration of the potential determining ion Ca2+ present in the initial brine. As the thickness of the water film decreases, the negative disjoining pressure causes the water film to break, and oil will contact the carbonate rock. The carboxylic groups, often present in molecules of the heavy end fraction of crude oil, then form strong bonds to the positively charged sites on the carbonate surface. Thus, the water wetness is drastically decreased as the amount of carboxylic material in the crude oil increases.4 The amount of carboxylic material can be quantified as an acid number (AN, expressed in term of mg of KOH/g), and the AN of the crude oil appeared to be the most important wetting parameter for carbonates.5 * Corresponding author. Tel: +47 9523 9086. Fax: +47 5183 1750. E-mail: [email protected]. (1) Chilingar, G. V.; Yen, T. F. Energy Sources 1983, 7, 67-75. (2) Austad, T.; Strand, S.; Høgnesen, E. J.; Zhang, P. Presented at the 2005 SPE International Symposium on Oilfield Chemistry, Houston, TX, Feb 2-4, 2005; SPE paper 93000. (3) Hirasaki, G.; Zhang, D. L. SPE J. 2003, June, 151-162. (4) Standnes, D. C.; Austad, T. J. Pet. Sci. Eng. 2000, 28, 111-121. (5) Zhang, P.; Austad, T. Presented at the 2005 SPE International Symposium on Oilfield Chemistry, Houston, TX, Feb 2-4, 2005; SPE paper 92999.

Previous studies by Standnes and Austad 6 showed that cationic surfactants of the ammonium type were able to improve spontaneous imbibition by wettability alteration, and it was later documented that the wettability modifying process was improved by the presence of sulfate in the imbibing fluid.7 The strong effect of sulfate inspired us to test seawater as a wettability modifier without the presence of expensive surfactants. The concentration of sulfate in seawater is about twice the concentration of calcium, and furthermore, sulfate is known to be a strong potential determining ion toward CaCO3.8 Surprisingly, it was observed that seawater appeared to act as a very good wettability modifier toward chalk, especially at high temperatures.2,9 The oil recovery from neutral-wet chalk cores using outcrop material increased as the concentration of sulfate in the imbibing seawater increased.10,11 The potential to improve oil recovery by using seawater as the wettability modifier in carbonates was also confirmed using Valhall reservoir chalk cores.12 The increase in oil recovery by spontaneous imbibition was 40% using seawater compared to the reservoir brine. Chromatographic wettability studies have shown that the adsorption of sulfate onto the chalk surface increased as the (6) Standnes, D. C.; Austad, T. J. Pet. Sci. Eng. 2000, 28, 123-143. (7) Strand, S.; Standnes, D. C.; Austad, T. Energy Fuels 2003, 17, 11331144. (8) Pierre, A.; Lamarche, J. M.; Mercier, R.; Foissy, A.; Persello, J. J. Dispersion Sci. Technol. 1990, 11 (6), 611-635. (9) Høgnesen, E. J.; Strand, S.; Austad, T. Presented at the SPE Europec/ EAGE Symposium, Madrid, Spain, June 13-16, 2005; SPE paper 94166. (10) Zhang, P.; Austad, T. Presented at the SPE Europec/EAGE Symposium, Madrid, Spain, June 13-16, 2005; SPE paper 94209. (11) Zhang, P.; Austad, T. Colloids Surf., A 2006, in press. (12) Webb, K. J.; Black, C. J. J.; Tjetland, G. Presented at the International Petroleum Technology Conference, Doha, Qatar, Nov 2123, 2005; IPTC paper 10506.

10.1021/ef0600816 CCC: $33.50 © 2006 American Chemical Society Published on Web 09/06/2006

Wettability Alteration and Oil RecoVery in Chalk

Energy & Fuels, Vol. 20, No. 5, 2006 2057

Table 1. Properties of the Oils Used

stirred for at least 48 h before use. Representative solutions were added to the cell for zeta potential measurements at 25 °C. Two series of tests were performed. For the first series, a small portion of concentrated CaCl2 solution was gradually added to the bulk chalk suspension; for the second series, the concentration of sulfate was kept constant in the suspension ([SO42-] ) 0.012 mol/L) while a small amount of concentrated CaCl2 solution was gradually added. For each measurement, the pH was kept constant at 8.4 by adjusting with small amounts of concentrated HCl or NaOH. The suspension was stirred for 2 min after new chemicals were added in order to achieve a new equilibrium before the measurement. IFT Measurement. The IFT measurements between oil and brine were performed at ambient temperature (18.5-20.2 °C) by using a ring tensiometer (Table 3). Core Handling. To obtain homogeneous wetting conditions, the cores were handled according to the procedures described by Standnes and Austad.4 Spontaneous imbibition experiments were performed on cores with and without initial water saturation. In the case without initial water, the dry cores were evacuated and saturated with oil under vacuum. They were then rested in the oil for 2 h, and the porosity was calculated by the weight difference, bulk volume, and oil density. The cores were then placed in Hassler core holders and flooded with 1.5 PV of oil in each direction with a confining pressure of 25 bar outside the rubber sleeve. Afterward, the cores were aged in a closed container at 50 °C for 5 days surrounded by the same oil. For cores with initial water, EF or EF-mod, the dry cores were evacuated and saturated with brine under a vacuum and the porosity was calculated after the cores were rested in the brine for 2 h. The cores were then flooded with 1.5 PV of oil in each direction with a confining pressure of 25 bar to obtain residual water saturation. The cores were aged in a closed container at 90 °C for at least 4 weeks using the same oil. Prior to the imbibition tests, the cores were shaved off about 2 mm at all surfaces using a lathe in order to remove the nonrepresentative adsorbed material on the core surface. Cores, which were used for chromatographic wettability tests, were wrapped with Teflon tape during aging. The main core parameters are summarized in Table 4. Spontaneous Imbibition. Long-term spontaneous imbibition studies were performed for tests with and without initial water present. The tests were performed at three different temperatures: 70, 100, and 130 °C. Standard Amott cells were used for tests performed at 70 °C, and steel cells were used for tests performed at 100 and 130 °C with a back-pressure of about 10 bar during the test period in order to keep the fluid below the bubble point. The detailed description of the high-temperature imbibition setup was reported previously.11 In cases where imbibition tests were performed at two temperatures, the change to a higher temperature was done after the plateau oil production was reached. Different imbibition fluids were used (Table 2), and some key parameters of the spontaneous imbibition tests are summarized in Table 4. Chromatographic Wettability Test. The chromatographic wettability test for chalk is based on the chromatographic separation of the nonadsorbing tracer thiocyanate, SCN-, and the potential determining ion, SO42-, at the water-wet sites inside the core. The test is done at residual oil saturation by core flooding using a Hassler core holder with a confining pressure less than 25 bar. The actual chalk core is flooded with a brine without sulfate and tracer thiocyanate, termed SW-U, at room temperature to reach the Sor, and then flooded with a brine containing sulfate and tracer thiocyanate, termed SW-M, at a constant rate of 0.2 mL/min. Small fractions (1.5-2.5 mL) of the effluent fluid were collected using a fraction collector. The concentration of SCN- and SO42- was analyzed for each of the samples, and the relative concentration is plotted against the pore volumes injected. The area (A) between the two curves is calculated by subtraction of the area under each of the curves, which were determined by the trapezoid method. Similarly, the separation area (A0) of a completely water-wet core containing n-heptane as reference oil can be quantified. Thereafter, the wettability index (WI) can be calculated as WI ) A/A0, where WI ranges from 0 to 1, representing completely oil-wet and completely water-wet conditions, respectively.

oil A B n-decane

ANa BNb asphaltene density viscosity (cp) (mg KOH/g) (mg KOH/g) content (wt %) (g/cm3) 2.07 0.55 0

0.50 0.13 0

0.23

0.806 0.803 0.731

3.05 2.56 0.65

a The AN was determined by West Lab Services according to ASTM D-664. b The BN was determined according to modified ASTM D-2289.

temperature increased, especially at temperatures above 100 °C.13 Sulfate is solvated by water molecules through hydrogen bonds; above 100 °C, these bonds break, and sulfate wants to leave the aqueous phase. In a dynamic equilibrium situation involving two potential determining ions of opposite charge, Ca2+ and SO42-, the adsorption onto the chalk surface is dependent on their relative concentration. Thus, adsorption of SO42- onto a positively charged chalk surface decreases the positive charge density, which then causes increased adsorption of Ca2+ to reestablish the new equilibrium.13,14 It is therefore reasonable to believe that both ions, Ca2+ and SO42-, are involved in the chemical mechanism for wettability alteration. The object of this paper is to study the symbiotic effect of Ca2+ and SO42- when using seawater as an imbibing wettability modifier. 2. Experimental Section Porous Media. Outcrop chalk from Stevns Klint (SK) near Copenhagen, Denmark, was used, which is a soft and highly porous media of the Maastrichtian age. The material is generally very homogeneous and composed of g96% fine-graded coccolithic matrix.15 It has low permeability (2-5 mD), high porosity (4550%), and a specific surface area of about 2 m2/g. All the chalk cores were drilled from the same outcrop chalk block and prepared to a dimension of L ≈ 70 mm and D ≈ 37.5 mm. Oil. Oil A was prepared by diluting a crude oil with n-heptane in a volume ratio of 60:40, respectively. No precipitation of asphaltenes was noticed during storage. The acid number, AN, of the resulting oil was 2.07 mg of KOH/g. Oil A was treated with silica gel to remove surface active materials, and the AN of the treated oil decreased to 0.17 mg of KOH/g.5 Oil B with an AN ) 0.55 mg of KOH/g was made by mixing Oil A with the treated low AN oil. The two crude oils were filtered through a 5 µm Millipore filter before use in order to improve the flow through the low permeable chalk cores. Heptane with purity >98% was used as a reference model oil. Some of the important parameters of the oils are listed in Table 1. Brine. Artificial Ekofisk formation brine (EF) was used as the initial brine. A modification of EF, termed EF-mod, with a much lower Ca2+ concentration was also used. The ionic strength for both EF and EF-mod was kept constant by adjusting the amount of NaCl. Synthetic seawater, SW, and modified SW (various Ca2+ and SO42concentrations) were used as imbibing fluids. Also, in this case, the ionic strength was kept constant (same as SW, 0.573 mol/L) by adjusting the concentration of NaCl. The brine, termed ZP, was used only for zeta potential measurements. The composition of the different brines is listed in Table 2. Zeta Potential. The zeta potential of aqueous chalk suspension was measured by using an AcoustoSizer from Matec Applied Sciences. The aqueous chalk suspension was prepared by mixing ZP-brine with 4.0 wt % milled chalk powder. The SK chalk material was milled for 48 h using a ball mill. The suspension was then (13) Strand, S.; Høgnesen, E.; Austad, T. Colloids Surf., A 2006, 275, 1-10. (14) Strand, S.; Standnes, D. C.; Austad, T. Presented at the 8th International Symposium on Reservoir Wettability and Its Effect on Oil Recovery, Rice University, Houston, TX, May 16-18, 2004. (15) Milter, J. Ph.D. Thesis, Department of Chemistry, University of Bergen, Bergen, Norway, 1996.

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Zhang et al. Table 2. Molar Composition of Brines

ion

SW×4Ca SW×3Ca SW×2Ca

Na+ K+ Mg2+ Ca2+ ClHCO3SO42ionic strength TDS (g/L)

0.333 0.010 0.045 0.052 0.486 0.002 0.024 0.657 30.9

0.372 0.010 0.045 0.039 0.499 0.002 0.024 0.657 31.7

0.411 0.010 0.045 0.026 0.512 0.002 0.024 0.657 32.6

SW

SW-1/2Ca SW-0Ca SW×4S SW×2S SW-1/4S SW-0S SW-U SW-M

0.450 0.010 0.045 0.013 0.528 0.002 0.024 0.657 33.4

0.470 0.010 0.045 0.006 0.532 0.002 0.024 0.657 33.8

0.489 0.010 0.045 0.538 0.002 0.024 0.657 34.0

Table 3. IFT between Brine and Oil Interfaces (mN/m) brine/oil

SW×4Ca SW×2Ca SW SW-0Ca

Oil A (AN ) 2.07 mg of KOH/g) Oil B (AN ) 0.55 mg of KOH/g)

11.9 12.2

12.3 12.1

12.5 12.3

12.2 12.7

3. Results and Discussions 3.1. Surface Charge of Chalk. Pierre et al.8 have shown that Ca2+ and SO42- act as potential determining ions toward CaCO3(s) in a NaCl solution. In Figure 1, the zeta potential on chalk particles in a 0.573 mol/L solution of NaCl is plotted versus the concentration of Ca2+ in the bulk chalk suspension. The pH of the solution was kept constant at 8.4. In the presence of a very low concentration of SO42-, 0.012 mol/L, the zeta potential decreased in the total concentration range of Ca2+. It is also noticed that a neutral charge condition is obtained at a concentration of Ca2+ close to the initial concentration of SO42-, i.e., [Ca2+] ) 0.012 mol/L. Thus, the relative concentration of Ca2+ and SO42- appeared to dictate the surface charge on chalk. 3.2. Impact of Ca2+ on Initial Wetting Condition. It has previously been documented by a new chromatographic wettability test that the water wetness decreased as the AN of the crude oil increased. With an initial water saturation of about 25%, the decrease in water wetness of chalk appeared to level off as the AN increased beyond 1.0 mg of KOH/g.14 An actual question to be asked is how sensitive the wetting conditions are to the concentration of Ca2+ in the initial brine. Two wettability tests were performed using initial brines with different concentrations of Ca2+, i.e., 0.231 and 0.013 mol/L, termed as EF and EF-mod, respectively. The cores were

0.378 0.010 0.045 0.013 0.309 0.002 0.096 0.657 31.0

0.426 0.010 0.045 0.013 0.453 0.002 0.048 0.657 32.6

0.468 0.010 0.045 0.013 0.579 0.002 0.006 0.657 34.0

0.474 0.010 0.045 0.013 0.597 0.002

0.500 0.010 0.045 0.013 0.623 0.002

0.657 34.2

0.683 35.72

EF

EF-mod

ZP

0.450 0.684 1.339 0.573 0.034 0.045 0.025 0.025 0.013 0.231 0.013 0.525 1.196 1.414 0.573 0.002 0.024 0.777 1.452 1.452 0.573 35.72 68.0 82.1 33.4

prepared using Oil A with high AN and aged as described. The initial water saturation was close to 23%. The corresponding reference cores, symbolizing completely water-wet conditions, were prepared using n-heptane as a model oil, and the initial water saturation was about 39%. The tests were performed as described in the Experimental Section and the fraction of waterwet area inside the core was determined according to the method previously described by Strand et al.14 The results are presented in Figures 2 and 3 for the high and low Ca2+ concentration, respectively. The area between the nonadsorbing tracer curve (SCN-) and the SO42- curves reflects the affinity of sulfate toward the chalk surface, and the wettability index (WI) is the ratio between the area for the crude oil system and the area for the reference n-heptane system. Wettability indexes of 0.793 and 0.786 were achieved for the high and low Ca2+ concentration brine, respectively. Thus, an increase in [Ca2+] by a factor of 18, from 0.013 to 0.231 mol/L, did not decrease the water wetness significantly. With an initial water saturation in the range of 23%, the concentration of Ca2+ appeared to have very small effects on the wetting condition of chalk. Seawater without sulfate, SW-0S, imbibed quite similarly into chalk cores with different initial concentrations of Ca2+, which also confirmed similar wetting conditions, Figure 4. 3.3. Effects of Ca2+ on Spontaneous Imbibition. To study the effects of Ca2+ on spontaneous imbibition of water into moderate water-wet or neutral-wet chalk, experiments have been performed with and without initial water present. The temperature has also been varied, 70 to 130 °C, to detect the impact of temperature on the wettability alteration process. In all cases, the imbibing fluid was SW or modified SW, where the concen-

Table 4. Experimental Details physical properties

saturation fluids

aging process

spontaneous imbibition

core ID

Da (cm)

La (cm)

φ (%)

initial water

oil

swi (%)

Taging (°C)

taging (days)

Timb (°C)

imbibing fluids

recovery (%OOIP)

Ca-1 Ca-2 CS 1-1 CS 1-2 CS 1-3 CS 1-4 CS 1-5 CS 2-1 CS 2-2 CS 2-3 CS 3-1 CS 3-2 CS 3-3 CS 4-1 CS 4-2 CS 4-3 CS 5-1 CS 5-2 CS 5-3 CS 5-4 CS 5-5 CS 5-6

3.73 3.75 3.54 3.54 3.51 3.50 3.50 3.51 3.54 3.51 3.55 3.55 3.55 3.54 3.54 3.54 3.52 3.54 3.44 3.55 3.52 3.51

6.03 5.59 5.10 5.05 5.10 5.10 5.16 5.85 5.58 6.33 5.45 5.32 4.85 6.08 6.41 5.93 6.55 5.72 5.94 6.39 6.06 5.78

47.2 48.1 49.8 49.3 48.3 48.3 48.4 47.6 48.9 48.5 48.1 48.9 48.2 47.5 47.3 47.2 49.0 47.9 50.3 48.5 49.8 48.6

EF EF-mod

Oil B Oil B Oil B Oil B Oil B Oil B Oil B Oil A Oil A Oil A Oil A Oil A Oil A Oil A Oil A Oil A Oil B Oil B Oil B Oil B Oil B Oil B

25.9 26.5 0.0 0.0 0.0 0.0 0.0 20.4 20.3 22.4 29.2 27.2 28.1 22.9 23.3 23.5 24.1 25.9 24.9 25.4 24.8 23.2

90 90 50 50 50 50 50 90 90 90 90 90 90 90 90 90 90 90 90 90 90 90

96 96 5 5 5 5 5 42 42 42 30 30 30 30 30 30 30 30 30 30 30 30

70 70 70 70 70 70 70 70f100 70f100 70f100 100f130 100f130 100f130 130 130 130 70 70 70 70 70 70

SW-0S SW-0S SW×4Ca SW×2Ca SW SW-1/2Ca SW-0ca SW×4Ca SW SW-0Ca SW×4Ca SW SW-0Ca SW-1/2Ca SW×4Ca SW SW×2S SW×2S SW SW SW-1/4S SW-1/4S

37.6 30.7 67.3 61.0 49.9 39.8 38.0 30.9f42.2 23.8f34.8 8.9f22.5 29.4f39.8 24.6f50.8 22.5f45.1 63.2 61.5 58.1 45.4 42.3 38.4 32.4 28.3 17.5

a

EF EF EF EF EF EF EF EF EF EF EF-mod EF EF-mod EF EF-mod

Measured after the core was shaved and both ends were cut.

Wettability Alteration and Oil RecoVery in Chalk

Figure 1. Zeta potential measurements on aqueous chalk suspension (with and without SO42- present) by gradually adding Ca2+ (pH 8.4). Measurements were done at 25 °C and initially 4 wt % milled chalk powders were mixed with brine ZP.

Figure 2. Chromatographic wettability test results for the chalk core aged in Oil A and a reference core saturated with n-heptane. EF was used as the initial brine. Tests were performed at ambient temperature.

Figure 3. Chromatographic wettability test results for the chalk core aged in Oil A and a reference core saturated with n-heptane. EF-mod was used as the initial brine. Tests were performed at ambient temperature.

tration of Ca2+ was varied below and above the concentration present in SW. It is important to note that the ionic strength was kept constant and similar to SW by adjusting the amount of NaCl. The concentration of SO42-, which is important in the wettability modifying process, was kept constant with a concentration similar to that of SW. The imbibition studies without initial water present were performed at 70 °C using Oil B (AN ) 0.55 mg of KOH/g). By experience, the wetting condition of the chalk using this oil would be close to neutral.14 Without initial brine present, the impact of Ca2+ is related only to the amount of Ca2+ present in the imbibing fluid. According to Figure 5, there is a systematic

Energy & Fuels, Vol. 20, No. 5, 2006 2059

Figure 4. Comparison of the effects of Ca2+ present in the initial brines on chalk wettability by performing spontaneous imbibition tests. EF or EF-mod was used as the initial brine, and Oil B was used as the oil phase. Tests were performed at 70 °C using SW-0S as imbibing fluid.

Figure 5. Spontaneous imbibition tests on chalk cores using different imbibing fluids with varying [Ca2+] but constant [SO42-]. Initially, chalk cores were 100% saturated with Oil B, and tests were performed at 70 °C.

increase in the oil recovery as the concentration of Ca2+ in the imbibing fluid increased. Thus, Ca2+ appeared to have a similar effect as SO42- to promote enhanced spontaneous imbibition of water. As an illustration, after 10 days, the oil recovery increased from about 17 to 42% as the concentration of Ca2+ in the imbibing fluid increased from 0 to 4 times the concentration present in SW. Even though spontaneous imbibition is mainly driven by capillary forces,11 the difference in oil recovery by using different amounts of Ca2+ in the imbibing fluid cannot be related to different IFT values between the injected brine and oil. As shown in Table 3, the IFT values are quite similar, about 12 mN/m. Thus, the results clearly document that Ca2+ together with SO42- played a very important role in the wettability alteration process. Normally, the initial brine of a carbonate reservoir contains lots of Ca2+, and the question is whether the spontaneous imbibition performance is also affected by the concentration of Ca2+ in the imbibing fluid even though the initial water has a high concentration of Ca2+. Experiments were performed using Oil A with high acid number (AN ) 2.07 mg of KOH/g). The initial water was EF brine with an initial saturation of about 20%. Results from spontaneous imbibition experiments at 70 and 100 °C, using imbibing fluids containing Ca2+ concentrations ranging from 0 to 4 times the concentration present in SW, are presented in Figure 6. Also, in this case, the impact of Ca2+ present in the imbibing fluid was dramatic. At 70 °C, less than 10% of the oil was recovered for the case without Ca2+

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Figure 6. Spontaneous imbibition tests on chalk cores using different imbibing fluids with varying [Ca2+] but constant [SO42-]. EF brine was used as the initial brine and Oil A was used as the oil phase. Tests were performed at 70 and 100 °C.

Figure 7. Spontaneous imbibition tests on chalk cores using different imbibing fluids with varying [Ca2+] but constant [SO42-]. EF brine was used as the initial brine and Oil A was used as the oil phase. Tests were performed at 100 and 130 °C.

present in the imbibing fluid, whereas the recovery increased to 30% if the imbibing fluid contained 4 times the concentration of Ca2+ compared with SW. As the temperature was increased to 100 °C, increased oil recovery was observed in all cases. It is of particular interest to note that the increase in oil by the increase in temperature was the highest for the imbibing fluid without Ca2+ present, and the chemical reason, which is related to a substitution of Ca2+ by Mg2+ at the chalk surface, will be discussed in more details in the forthcoming paper.16 Similar experiments were conducted at 100 and 130 °C, Figure 7. The impact of Ca2+ was smaller, with a starting temperature of 100 °C compared to 70 °C. The same general trend was, however, followed, i.e., increased amount of Ca2+ caused increased oil recovery. When the temperature was changed to 130 °C during the imbibing process, the imbibing fluid with the highest concentration of Ca2+ produced that lowest amount of oil. The reason is that the solubility of CaSO4 is exceeded at 130 °C. It is well-known that the solubility of CaSO4 increases to a maximum at a temperature close to 100 °C, and the solubility then decreases drastically as the temperature increases beyond 100 °C.9 The solubility is enhanced in the presence of Mg2+, which forms an ion pair with SO42- 17

[Mg2+SO42-]aq ) Mg2+ + SO42(16) Zhang, P.; Tweheyo, M. T.; Austad, T. J. Colloid Interface Sci. 2006, to be submitted. (17) Carlberg, B. L.; Matthews, R. R. Presented at the SPE Oilfield Chemistry Symposium, Denver, CO, May 24-25, 1973; SPE paper 4353.

Zhang et al.

Figure 8. Solubility of CaSO4 at 100 and 125 °C for mixtures of SW×4Ca and EF. Precipitation of CaSO4 is expected in the shadowed region.

At a given ionic strength, the equilibrium moves to the left as the temperature is increased, which lowers the activity of SO42and prevents precipitation as CaSO4. This is the reason seawater can be used as the injection fluid even in reservoirs at 130 °C without precipitation of CaSO4. The solubility of CaSO4 has been calculated for mixtures of SW×4Ca and EF brine at 100 and 125 °C using the method by Calberg and Matthews17 and is graphically presented in Figure 8. At 100 °C, no precipitation of CaSO4(s) by mixing SW×4Ca and EF brine will take place. It is, however, evident from the plot that the solubility of CaSO4 at 125 °C is exceeded for the mixtures when the volume fraction of SW×4Ca is higher than 0.42. Knowing that CaSO4(s) is even less soluble at 130 °C, the reason for the decreased oil recovery at 130 °C when using SW×4Ca must be related to the precipitation of CaSO4(s) in the pore system. Thus, the concentration of both of the important potential determining ions Ca2+ and SO42- decreases, and fluid flow may be prevented because of precipitated material. It was observed that the normalized permeability of the chalk core decreased by more than 80% during hydrostatic tests when modified seawater containing 4 times the sulfate (SW×4S) was injected through the core at 130 °C.18 A series of experiments were also conducted by doing spontaneous imbibition studies at 130 °C directly. The initial brine was EF water, and the concentration of Ca2+ in the imbibing fluids varied between 1/2 and 4 times the concentration present in SW, Figure 9. In all cases, the oil recovery was fast and reached about 60%. The impact of [Ca2+] vanished. Even though SW×4Ca is not compatible at a temperature of 130 °C, the fluid imbibed quite well into the core. The precipitation of CaSO4(s) took place in the bulk imbibing solution and was visually confirmed inside the imbibition cell at the end of the test. The imbibing fluid displaces both the oil and the initial water present.19 The front of the imbibing fluid is somewhat depleted in Ca2+ and SO42- because of adsorption onto the chalk surface, and precipitation of CaSO4(s) will not occur inside the porous system.14 Even though it was impossible to detect any difference in the wetting conditions of chalk when using initial brines with quite different concentrations of Ca2+, the concentration of Ca2+ in the initial brine may have an influence on spontaneous (18) Korsnes, R. I.; Madland, M. V.; Austad, T. Paper to be presented at the European Regional EUROCK06 Conference, University of Lie`ge, Lie`ge, Belgium, May 9-12, 2006. (19) Nielsen, C. M.; Olsen, D. Presented at the 2000 SPE Annual Technical Conference and Exhibition, Dallas, TX, Oct 1-4, 2000; SPE paper 63226.

Wettability Alteration and Oil RecoVery in Chalk

Figure 9. Spontaneous imbibition tests on chalk cores using different imbibing fluids with varying [Ca2+] but constant [SO42-]. EF brine was used as the initial brine and Oil A was used as the oil phase. Tests were performed at 130 °C.

Energy & Fuels, Vol. 20, No. 5, 2006 2061

tion and water injection, including the relationship between wettability and temperature,5 the affinity of Ca2+ and SO42toward the chalk surface as studied by chromatographic methods,14 the effects of temperature on adsorption of potential determining ions,13 the effects of temperature on oil recovery by spontaneous imbibition,9 and the impact of sulfate present in seawater on oil recovery.10,11 Taking into account the results from the listed previous studies and the results from the present study, we can suggest a chemical mechanism for the wettability modification as follows: Sulfate present in seawater will adsorb onto the positively charged chalk surface and lower the positive surface charge. Because there will then be less electrostatic repulsion, more Ca2+ can adsorb onto the chalk surface, and the excess of Ca2+ is close to the chalk surface. Ca2+ can then react with adsorbed carboxylic grou bonded to the chalk surface and release some of the organic carboxylic materials. The process is schematically illustrated in Figure 11. Later studies have shown that Mg2+ present in seawater also acts as a potential determining ion toward the chalk surface, and it will have impact on the wettability modification, especially at high temperatures. The experimental results will be presented in the next paper in this series.16 4. Conclusion

Figure 10. Comparison of the effects of [Ca2+] present in the initial brines on wettability alteration at 70 °C using different imbibing fluids (SW and modified SW with varying [SO42-]). EF or EF-mod was used as the initial brine, Oil B was used as the initial oil phase.

imbibition performance by wettability alteration. The relationship between the concentration of Ca2+ in the initial brine and the amount of SO42- in the imbibing fluid was studied. Two series of cores were prepared with initial brine containing 0.231 and 0.013 mol/L calcium, EF, and EF-mod brine, respectively. The concentration of sulfate in the imbibing fluid varied between 1/ and 2 times the concentration present in SW, whereas the 4 concentration of Ca2+ in the initial brine was kept constant and equal to the concentration in SW. The cores were prepared using Oil B, and the imbibing tests were conducted at 70 °C, Figure 10. As a general observation, (1) the imbibing fluid containing the highest concentration of SO42- imbibed most strongly, (2) the core containing the highest concentration of Ca2+ in the initial brine imbibed more strongly than the core with lower initial Ca2+ concentration, (3) the impact of Ca2+ in the initial brine appeared to be less significant as the concentration of SO42- in the imbibing fluid increased. 3.4. Suggested Mechanism. The motivation for our studies on oil recovery from chalk has been to understand why seawater is such a good injection fluid into the Ekofisk field in the North Sea. The estimated oil recovery is now approaching 50%. The reservoir rock is a highly fractured chalk with low matrix permeability, and the reservoir temperature is high, 130 °C. Chalk is a very special reservoir rock because of the pure biogenic nature, and the surface of the chalk is therefore rather reactive. From the present imbibition study, it can be concluded that Ca2+ is also an active agent in increasing spontaneous imbibition of water into moderate water-wet chalk. In a series of previous papers, we have studied the surface chemistry of chalk in relation to improved oil recovery by wettability altera-

The type and relative concentration of potential determining ions toward chalk makes seawater a very interesting injection fluid into fractured chalk, especially at high temperatures. The impact of Ca2+, both in the initial brine and the imbibing fluid, has been studied, and the results are summarized as follows: Different concentrations of Ca2+ in the initial brine did not result in significant differences in chalk wettability when using an oil with a high acid number. The oil recovery by spontaneous imbibition was improved when the concentration of Ca2+ was increased in both the injection fluid and the initial brine. There appeared to be a symbiotic effect of Ca2+ and SO42- on the wettability alteration process, which is temperature-dependent. A chemical mechanism for desorption of carboxylic material from the chalk surface was suggested that involved coadsorption of SO42- and Ca2+ onto the water-wet sites of the chalk surface. Acknowledgment. The authors acknowledge ConocoPhillips and the Ekofisk Coventurers, including TOTAL, ENI, Hydro, Statoil, and Petoro, for financing the work and for permission to

Figure 11. Suggested wettability alteration mechanism in chalk. The desorption of carboxylic materials is initiated because of the change in surface charge by the coadsorption of SO42- and Ca2+.

2062 Energy & Fuels, Vol. 20, No. 5, 2006 publish this paper from the research center COREC. We thank the Norwegian Research Council, NFR, for financial support, Statoil for delivering the oil, and Senior Researchers D. Olsen and P. Frykman at GEUS, Copenhagen, Denmark, for providing the chalk material.

Nomenclature A, A0 ) Separation area in the chromatographic wettability test AN ) Acid number ASTM ) American Society for Testing and Materials BN ) Base number C ) Effluent concentration of sulfate or tracer C0 ) Injected concentration of sulfate or tracer C/C0 ) Relative concentration of ions in effluent fractions conc. ) Concentration D ) Core diameter

Zhang et al. EF ) Ekofisk formation water φ ) Core porosity IFT ) interfacial tension WI ) Chromatographic wettability index L ) Core length PV ) Pore volume SK ) Stevns Klint Sor ) Residual oil saturation SW ) Synthetic seawater Swi ) Initial water saturation taging ) Aging time Taging ) Aging temperature Timb ) Imbibition temperature TDS ) Total dissolved solid vol. ) Volume EF0600816