ARTICLE pubs.acs.org/EF
Initial Wetting Properties of Carbonate Oil Reservoirs: Effect of the Temperature and Presence of Sulfate in Formation Water Seyed Farzad Shariatpanahi,* Skule Strand, and Tor Austad Department of Petroleum Engineering, Faculty of Science and Technology, University of Stavanger, 4036 Stavanger, Norway ABSTRACT: Water-based enhanced oil recovery (EOR) from carbonates is usually restricted by initial wetting properties, especially in naturally fractured carbonates. Carboxylic material in the crude oil, quantified by the acid number (AN), is regarded as the most important wetting parameter. In this paper, it is shown experimentally that, for a given AN, the temperature and the amount of sulfate present in the formation water will affect the wetting condition significantly. The concentration of sulfate in the formation water is usually low because of a high amount of Ca2+, anhydrite, CaSO4(s), is precipitated at high temperatures. The interaction between small amounts of sulfate dissolved in the formation water and the rock surface was studied using chalk cores. The relative amount of sulfate dissolved in the pore water, SO42(aq), and sulfate adsorbed onto the chalk surface, SO42(ad), was quantified at different temperatures of 20, 50, 90, and 130 °C. Below 50 °C, the relative amount of SO42(aq) and SO42(ad) was quite constant, but above 50 °C, SO42(aq) decreased, while SO42(ad) was not significantly affected by increasing the temperature. Sulfate was precipitated as CaSO4(s) and retained in the core at 130 °C. Spontaneous imbibition of formation water, free from sulfate, was also conducted at 50 °C into mixed wet chalk cores, which were aged at different temperatures. When the aging temperature increased, the oil recovery by spontaneous imbibition decreased. Separate wettability tests also confirmed the increase in water-wetness as the aging temperature was lowered. The amount of sulfate present in the pore water, SO42(aq), appeared to be the active sulfate species to increase the water-wetness, which was in line with the previously suggested mechanism for wettability alteration by seawater in carbonates. For the tested aging temperatures of 50, 90, and 130 °C, changes in wetting properties appeared to take place at sulfate concentrations in the formation water below 2 mmol/L. At higher concentrations of sulfate, the wetting properties were not significantly affected.
’ INTRODUCTION The success of oil recovery from carbonates by water injection is very much linked to the initial wetting conditions of the rock, especially for naturally fractured reservoirs, where capillary forces are considered as the main driving force for displacement of oil from the matrix blocks into the fracture networks. At high temperatures, T > 90100 °C, seawater is able to improve the waterwetness of the carbonate surface because of a symbiotic interaction between Ca2+, Mg2+, and SO42 at the rock surface. A chemical mechanism has been suggested for desorption of organic carboxylic material from the carbonate surface.1,2 Sulfate, which is usually regarded as a trace element in the formation water, appeared to act as a catalyst for the wettability alteration process, and in that way, it is a key parameter. Improved oil recovery can even be obtained by modifying the seawater, increasing the sulfate concentration, or removing NaCl from the seawater.3,4 In a previous study, it was observed that even very small amounts of sulfate present in outcrop chalk cores had great effects on the initial wetting properties of the rock.5 The oil recovery by spontaneous imbibition of formation water into a chalk core, preflooded with distilled water to remove sulfate, was about 30% original oil in place (OOIP) lower compared to a nontreated core, which corresponded to a decrease in the water-wet surface fraction of 23%. Thus, in the same way as SO42 in the presence of Ca2+ and/or Mg2+ in the injected fluid is able to improve water-wetness of carbonates, the presence of sulfate in the formation water should also affect the initial wetting conditions. The salinity of formation water in carbonate reservoirs may vary significantly from seawater salinity (≈33 000) to above r 2011 American Chemical Society
250 000 ppm. The concentration of Ca2+ is usually high, while the amount of Mg2+ is much lower, usually by a factor of more than 10. Some limestone reservoirs contain precipitated anhydrite, CaSO4(s), as a part of the rock material. The dissolution of anhydrite in formation water is low because of the high temperature and high concentration of Ca2+, the common ion effect. A high content of Cl has, however, a positive effect on dissolution of CaSO4(s) because of the complex formation between Ca2+ and Cl. In addition to Ca2+ and Mg2+, SO42 is also a potential determining ion toward calcite, which means that sulfate will adsorb onto the carbonate surface and affect the ζ potential.6 Thus, in a given formation brinecarbonate system containing anhydrite, the following chemical equilibrium will be present: CaSO4 ðsÞ T Ca2+ + SO4 2 ðaqÞ T CaCO3 ðsÞ 3 3 3 SO4 2 ðadÞ ð1Þ Anhydrite, as a solid material, is probably not the active species in the wettability alteration process, and the question that we ask is the following: “What is the active species of sulfate, SO42(aq) dissolved in the brine or SO42(ad) adsorbed onto the rock, that is responsible for the initial wetting condition of a carbonate reservoir containing precipitated anhydrite or small amounts of sulfate present in the formation water?” Received: January 6, 2011 Revised: June 7, 2011 Published: June 07, 2011 3021
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Table 1. Brine Compositions ions
VB-0S (mol/L)
VB-2S (mol/L)
VB-6S (mol/L)
VB-17S (mol/L)
SW0T (mol/L)
SW1/2T (mol/L)
HCO3
0.009
0.009
0.009
0.009
0.002
0.002
Cl
1.066
1.060
1.051
1.025
0.583
0.583
SO42
0.000
0.002
0.006
0.017
0.000
0.012
SCN
0.000
0.000
0.000
0.000
0.000
0.012
Mg2+
0.008
0.008
0.008
0.008
0.045
0.045
Ca2+
0.029
0.029
0.029
0.029
0.013
0.013
Na+
0.997
0.996
0.994
0.989
0.460
0.427
K+ TDS (g/L)
0.005 62.83
0.005 62.83
0.005 62.83
0.005 62.83
0.000 33.39
0.022 33.39
IS (mol/L)
1.112
1.109
1.111
1.117
0.643
0.645
The impact of temperature on the above-mentioned chemical equilibrium is complicated. The dissolution of CaSO4(s) may go through a maximum as the temperature is increased if a large amount of Mg2+ is present. The adsorption of SO42 and co-adsorption of Ca2+ increases as the temperature increases.2,7 Furthermore, Mg2+ is in some cases able to substitute Ca2+ at the carbonate surface as the temperature increases.1,6 In this work, small amounts of sulfate were added to a ≈63 000 ppm formation brine, which corresponded to 27, 53, and 135% of sulfate present in ordinary seawater. The brinerock interaction was studied at 4 different temperatures (room temperature, 50, 90, and 130 °C). Furthermore, cores containing different amounts of sulfate in formation water were flooded with crude oil, aged at the desired temperatures, and spontaneously imbibed by formation water depleted in sulfate at 50 °C. The oil recovery and initial wetting conditions are discussed in terms of the rockfluid interaction at the different temperatures.
’ EXPERIMENTAL SECTION Porous Media. Outcrop chalk from Stevns Klint (SK), nearby Copenhagen, Denmark, was used as core material. All of the cores were drilled from the same chalk block in the same direction. Chalk cores have high porosity (4550%) and low permeability (25 mD) and are considered as a very homogeneous material. All of the cores were shaved and cut to 70 mm in length and 38 mm in diameter. Crude Oil. A stabilized crude oil with an acid number (AN) = 2.90 mg of KOH/g and a base number (BN) = 0.95 mg of KOH/g was used as a basic oil. This oil was diluted with 40 vol % heptane, centrifuged, and filtrated through a 0.65 μm Millipore filter. No precipitation of asphaltenic material was observed during storage. Surface-active material was removed from the oil using silica gel, as described by Zhang et al.7 When the base oil and silica-treated oil were mixed, an oil with AN = 0.55 mg of KOH/g and BN = 0.20 mg of KOH/g was obtained which was used in the experiments. The density and viscosity of the prepared oil were determined to be 0.810 g/cm3 and 3.1 cP, respectively. Brines. The different brines were made from deionized (DI) water and the available reagent-grade salts. The brine solutions were filtered through a 0.22 μm Millipore filter. The respective brine compositions are listed in Table 1, and the terminology is as follows: (1) VB-0S is the formation brine free of sulfate, which was used as the initial formation water in the reference system and also as imbibing brine in the spontaneous imbibition tests. (2) VB-2S is VB-0S containing 2 mmol/L SO42 (10% sulfate concentration in North Sea seawater) used as formation water. (3) VB-6S is VB-0S containing 6 mmol/L SO42 (25% sulfate concentration in North Sea seawater), used as formation water. (4) VB-17S is VB-0S
containing initially 17 mmol/L SO42 (70% sulfate concentration in North Sea seawater), used as formation water. For the different formation brines, the total dissolved salt (TDS) was kept constant by adjusting the amount of NaCl (Table 1). To distinguish the full strength brines, containing different concentrations of sulfate, from their dilutions, terms 0.1VB-0S, 0.1VB-2S, 0.1VB-6S, and 0.1VB-17S were used, respectively, when formation brines were diluted 10 times. The following brines were also used in the chromatographic wettability test, which is explained in detail later in this paper: (1) SW0T is North Sea seawater without SO42. (2) SW1/2T is North Sea seawater containing 12 mmol/L SCN and SO42. BrineChalk Interaction. The brinerock interaction at different temperatures (room temperature, 50, 90, and 130 °C) was studied using 10 times diluted formation brine containing different amounts of sulfate (0.1VB-0S, 0.1VB-2S, 0.1VB-6S, and 0.1VB-17S). For each system, the equilibrium between sulfate present in the pore water, termed SO42(aq), and sulfate adsorbed onto the rock, termed SO42(ad), was established at room temperature by flooding 56 pore volumes (PVs) of diluted formation water in each direction (0.2 mL/min). Negligible substitution of Ca2+ by Mg2+ at the chalk surface was expected at room temperature. The effluent of the core flooding in each direction was analyzed for sulfate to confirm that the equilibrium was established. The amount of SO42(aq) and SO42(ad) was quantified by flooding the cores with DI water (0.2 mL/min). The concentration of sulfate in the effluent was determined. The amount eluted during 1 PV was related to SO42(aq), and the sulfate eluted after 1 PV was related to SO42(ad). When the effect of the temperature was tested on the equilibrium between SO42(aq) and SO42(ad), three cores were flooded with 0.1VB-6S at room temperature and then aged at different temperatures (room temperature, 50, 90, and 130 °C) for 3 days, after the equilibrium was established at room temperature. Each of the cores then contained approximately the same total amount of initial sulfate. Then, the cores were flooded at the respective temperatures with DI water (0.2 mL/min). The amount of SO42(aq) and SO42(ad) was quantified as described above. To confirm precipitation of CaSO4(s), the test at 130 °C was repeated with a new core. After the core was flooded with DI water at 130 °C (5 PVs), the flooding was stopped and the core was aged at room temperature for 3 days. Finally, the core was flooded with DI water (0.2 mL/min) at room temperature, and the amount of SO42(aq) and SO42(ad) was quantified as described above. The eluted amount of Mg2+ and Ca2+ was also quantified. Core Preparation for Oil Recovery. The cores were initially flooded with about 5 PVs of DI water at room temperature to remove initially precipitated salts, especially SO42, as described by Puntervold et al.5 Then, the cores were dried at 90 °C to a constant weight. The dried cores were evacuated and saturated with DI water and flooded with 5 PVs of 10 times diluted formation brine in each direction at room temperature and 3022
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Figure 1. Relative concentration of sulfate in the effluent when the core was flooded with 0.1VB-2S with the rate of 0.2 mL/min at room temperature. left in the core holder for a few hours. Initial water saturation, Swi ≈10%, was established by draining the cores in a desiccator, which contained silica gel as the drying agent. The cores were then equilibrated in a sealed container for 3 days to obtain uniform water saturation.8 Then, the cores were flooded with crude oil (2 PVs in each direction) at 50 °C. Finally, the cores were properly wrapped with Teflon tape and aged in the crude oil using a stainless-steel aging cell for 4 weeks at elevated temperatures. Spontaneous Imbibition. Chalk cores, aged at different temperatures and with different amounts of sulfate present in the formation water, were imbibed with VB-0S at 50 °C using standard glass Amott cells. The volume of produced oil, calculated as % OOIP, was recorded as a function of the time. Chromatographic Wettability Test. The chromatographic wettability test for carbonates was used to determine the water-wet fraction of the chalk cores after imbibition of VB-0S.9 The method is based on the separation of the tracer, SCN, and SO42 at the water-wet sites of the carbonate surface. The area between the effluent curve of SCN and SO42 is directly proportional to the water-wet surface area. Using a completely water-wet core as a reference system, the ratio between the two areas will give a wetting index, which describes the water-wet fraction of the surface area (WI). Thus, WI = 1, 0.5, and 0 represent completely water-wet, neutral, and completely oil-wet systems, respectively WI ¼
Awet Aref
ð2Þ
where Awet is the area between the effluent curve of SCN and SO42 for the actual sample and Aref is the area between the effluent curve of SCN and SO42 for a completely water-wet reference sample. Chemical Analysis. The composition of the effluent in core flood experiments was determined using an ion chromatograph, ICS-3000 reagent-free, produced by Dionex Corporation, Sunnyvale, CA.
’ RESULTS AND DISCUSSION Equilibrium between SO42(aq) and SO42(ad) at Room Temperature. To prevent precipitation of CaSO4(s), the forma-
tion waters used were diluted 10 times when studying the impact of sulfate on the rockfluid interaction in pure chalk outcrop cores. At low concentrations of sulfate, it will be easier to observe the impact of the temperature on the relative amount of SO42(aq) and SO42(ad). The concentration of sulfate in the respective full strength test brines was low (217 mmol/L). A total of 5 PVs of diluted brines (0.1VB-2S, 0.1VB-6S, and 0.1VB-17S) were flooded (0.2 mL/min) at room temperature through the cores, and the concentration of SO42 in the effluent was analyzed. The relative concentration, C/Co, was plotted versus the PV injected, as shown by Figure 1, for the 0.1VB-2S brine. After
Figure 2. Effluent sulfate content from the cores saturated with 0.1VB2S, 0.1VB-6S, and 0.1VB-17S when the core was flooded with DI water with the rate of 0.2 mL/min at room temperature.
Figure 3. Concentration ratio of SO42(aq)/SO42(ad) versus the initial concentration of sulfate in formation water, showing a constant ratio for different concentrations of sulfate at room temperature.
34 PVs, the concentration of sulfate in the effluent was similar to the concentration of injected brine. To be sure that equilibrium between SO42(aq) and SO42(ad) was established, the flow direction was reversed and the concentration ratio remained close to 1 during 5 PVs. It is therefore supposed that a chemical equilibrium between SO42(aq) and SO42(ad) was established for the different cases at room temperature. Each of the three cores was then flooded with DI water (0.2 mL/min) at room temperature to displace the brine. Again, the concentration of SO42 in the effluent was analyzed, and the concentration was plotted versus PVs of DI water injected (Figure 2). The shape of the effluent concentration curve indicates that the amount of sulfate produced during the first PV was related to sulfate dissolved in the brine, SO42(aq), while the amount corresponding to the peak was related to sulfate adsorbed in the diffuse layer, SO42(ad). It was believed that sulfate was evenly distributed in the core body with an established equilibrium between SO42(aq) and SO42(ad). To confirm that the equilibrium between SO42(aq) and SO42(ad) was achieved, the concentration ratio of SO42(aq)/SO42(ad) was plotted versus the initial concentration of sulfate in the formation water, and the concentration ratio remained a quite constant ratio for the different concentrations of sulfate (Figure 3). Spontaneous Imbibition. Reference System. The sulfate equilibrium will change as the temperature is increased, and the impact of wetting properties could be qualitatively evaluated by spontaneous imbibition. To have a reference system without sulfate present, three cores were prepared as described in the Experimental 3023
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Figure 4. Spontaneous imbibitions of VB-0S into the cores containing VB-0S as formation brine and oil with AN = 0.55 mg of KOH/g and BN = 0.2 mg of KOH/g. Ttest = 50 °C.
Figure 5. Spontaneous imbibition of VB-0S into the cores containing VB-2S as formation water and oil with AN = 0.55 mg of KOH/g and BN = 0.2 mg of KOH/g. Ttest = 50 °C.
Section. The cores were aged in the crude oil at different temperatures of 50, 90, and 130 °C. Spontaneous imbibition at 50 °C using VB-0S was performed, and the results are shown in Figure 4. Obviously, the cores aged at 90 and 130 °C appeared less water-wet compared to the core aged at 50 °C. Whether this is a kinetic effect; i.e., equilibrium has not been obtained, or a real temperature effect is uncertain. Within the accuracy of the test, it is not possible to discriminate between the imbibition test for the cores aged at 90 and 130 °C. VB-2S as Formation Brine. A similar imbibition test series was performed using formation water spiked with sulfate, i.e., VB-2S, which contained the lowest amount of sulfate. Otherwise, the cores were treated exactly in the same way as the reference system described above. The cores were imbibed at 50 °C using VB-0S as imbibing fluid, and the results are shown in Figure 5. In comparison to the reference system without any sulfate present in the formation water, the cores containing even a very small amount of sulfate appeared significantly more water-wet, and the waterwetness increased as the aging temperature decreased. In this case, there is a significant difference between the cores aged at 90 and 130 °C. Impact of the Amount of Sulfate on Oil Recovery. Obviously, the presence of sulfate affected the initial wetting condition, and a natural question is as follows: “Is the initial wetting condition sensitive to the total amount of sulfate initially present in the core body?” To test this, we increased the amount of sulfate about 9 times in the formation brine from 2 to 17 mmol/L (brine VB-17S; Table 1) and a new series of imbibition tests were performed in
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Figure 6. Spontaneous imbibition of VB-0S into the cores containing VB-17S as formation water and oil with AN = 0.55 mg of KOH/g and BN = 0.2 mg of KOH/g. Ttest = 50 °C.
Figure 7. Effect of sulfate in formation brine on oil recovery from cores aged at different temperatures.
the same way as the previous tests. As shown by Figure 6, the different oil recovery curves were quite similar to the results shown in Figure 5; i.e., increasing the amount of sulfate beyond the value of 2 mmol/L in the formation water did not change the oil recovery significantly, as shown by Figure 7. Thus, the wetting conditions appeared to be quite similar for the two test series with different contents of sulfate in the formation water. It must be noticed that no wettability alteration is expected to take place during the oil recovery process because no sulfate was present in the imbibing formation fluid (VB-0S). Impact of Sulfate on the Initial Wetting Condition. To verify that the difference in oil recovery between the cores without and with initial sulfate (2 mmol/L) was related to different wetting conditions, chromatographic wettability tests were performed on the cores after being imbibed with VB-0S at 50 °C. As an example, only the results of the wettability tests on the cores aged at 90 °C are shown graphically. The oil recovery from the core without initial sulfate was about 7% (Figure 4) compared to about 23% for the core containing initial sulfate (Figure 5). The chromatographic wettability test for the two cores is shown in Figures 8 and 9, respectively. The area between the tracer, SCN, and sulfate elution curve is proportional to the water-wet area inside the core, and the value of the area was calculated as 0.149 and 0.199 for the core without and with sulfate present in the formation water, respectively. The corresponding area for a completely water-wet core was 0.275. Wetting indexes (WI) describing the water-wet fraction of the surface area of the respective cores with and without sulfate present in the formation water could then be calculated. The results are presented in Figure 10. The water-wet fraction of the 3024
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Figure 8. Chromatographic wettability test on the core containing VB0S as formation water after SI test. Conditions: aging temperature, 90 °C; chromatographic brines, SW0T and SW1/2T; test at room temperature; C/Co, relative concentration of SCN and SO42.
Figure 10. Water wet fraction (WI) of the cores containing VB-0S and VB-2S as formation waters at different aging temperatures.
Figure 9. Chromatographic wettability test on the core containing VB-2S as formation water after SI test. Conditions: aging temperature, 90 °C; chromatographic brines, SW0T and SW1/2T; test at room temperature; C/Co, relative concentration of SCN and SO42.
Figure 11. Oil recovery from the cores containing VB-0S, VB-2S, and VB-17S as formation brines at different aging temperatures. Oil with AN = 0.55 mg of KOH/g was used, and VB-0S was used as imbibing brine. Ttest = 50 °C.
cores, which contained initial sulfate in the formation water, was consistently higher than for the cores without sulfate in the formation water for all of the aging temperatures. For the cores without initial sulfate in the formation water, the water-wet fraction (WI) was close to 0.5, which corresponded to a neutral wetting property. For the cores containing sulfate, the water-wet fraction increased from 0.59 to 0.72 as the aging temperature decreased from 130 to 50 °C. Thus, the difference in oil recovery by spontaneous imbibitions could be related to differences in initial wetting conditions as summarized in Figures 10 and 11. Relative Impact of SO42(aq) and SO42(ad) on Wetting Conditions. The next questions to be asked about the effect of sulfate present in the formation water are as follows: “Why does the water-wetness decrease as the temperature is increased? Is it related to the change in the relative concentration of SO42(aq) and SO42(ad)?” The effect of the temperature on the partitioning of sulfate between the pore water and the rock surface was studied by applying a concentration of sulfate in the brine, which was in between the other two test series. VB-0S was spiked with 6 mmol/L sulfate, (VB-6S; Table 1), and the brine was diluted 10 times prior to use for rockfluid interaction studies (0.1VB-6S). The cores were flooded at room temperature with the brine as described previously, and equilibrium between SO42(aq) and SO42(ad) was established at room temperature. Prior to the tests, the different cores were aged at the test temperatures of 20, 50, 90, and 130 °C for 3 days. Then, the cores were flooded with DI water at the respective aging temperatures. The sulfate concentration of the effluent was plotted against the PV injected (Figure 12). The concentration of sulfate linked to the pore water,
SO42(aq), decreased as the temperature increased.2 The peak associated with the amount of sulfate adsorbed onto the surface, SO42(ad), became broader and moved to the right, i.e., in line with a stronger adsorption of sulfate onto the chalk surface, as the temperature is increased. Surprisingly, the area of the different peaks was quite similar, and therefore, the amount of SO42(ad) was quite constant, about 3 mg, as shown in Table 2. Initially, each of the cores contained the same total amount of sulfate because they were prepared in the same way at room temperature, but the total amount of sulfate recovered, SO42(aq) and SO42(ad), by flooding with DI water decreased significantly as the temperature increased beyond 50 °C, from ≈4.5 to 2.9 mg (Table 2). No significant difference in the total recoverable sulfate was observed by increasing the temperature from 20 to 50 °C, but the ratio between SO42(aq) and SO42(ad) decreased a little. In fact, the amount of SO42(aq) decreased to the same extent as SO42(ad) increased. As the temperature was increased from 50 to 90 °C, the total extractable amount of sulfate decreased by 11%, from 4.5 to 4.0 mg. The ratio between SO42(aq) and SO42(ad) decreased, however, significantly, from 0.53 to 0.26. In the temperature step from 90 to 130 °C, the recoverable amount of sulfate decreased even more (28%) from 4.0 to 2.9 mg and the ratio between SO42(aq) and SO42(ad) decreased to 0.10 (Table 2). Thus, as the temperature increased from 20 to 130 °C, about 35 wt % of the sulfate is retrained irreversibly, i.e., not extractable by flooding with DI water. Thus, irreversible retention of sulfate appeared to be a temperature phenomenon, and because there is not a significant increase in the loss of sulfate 3025
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Figure 12. Relative amount of sulfate dissolved in the pore water and sulfate adsorbed onto the rock at different temperatures. The cores was saturated and flooded at Troom, aged at elevated temperatures using 0.1VB-6S, and then flooded at the same temperature with DI water. Injection rate = 0.2 mL/min.
Figure 13. Relative amount of sulfate dissolved in the pore water and sulfate adsorbed onto the rock at 130 °C and room temperature using 0.1VB-6S. The core was flooded with DI water. After switching to room temperature, the core was aged for 3 days prior to further flooding with DI water. Injection rate = 0.2 mL/min.
Table 2. Equilibrium between SO42(aq) and SO42(ad) at Different Temperatures, with 0.1VB-6S Used as Formation Water temperature SO42(aq) SO42(ad) (°C)
(mg)
(mg)
20 50
1.6 1.4
3.0 3.1
SO42(aq) + SO42(ad) 4.6 4.5
(mg)
SO42(aq)/ SO42(ad) 0.69 0.53
90
0.36
3.4
4.0
0.26
130
0.03
2.8
2.9
0.10
between 20 and 50 °C, it is appropriate to believe that a negligible amount of sulfate is irreversibly retained at low temperatures. Only about 65% of the sulfate was recovered at 130 °C compared to the amount recovered at temperatures below 50 °C, and what is the reason for that? Precipitation of anhydrite, CaSO4(s), is a possible explanation. The solubility of CaSO4(s) is affected by the temperature and concentration of Mg2+; i.e., the solubility is depressed by an increase in the temperature and decrease in Mg2+. The concentration of Mg2+ is strongly decreased because of the substitution of Ca2+ at the chalk surface.1,6 No significant dissolution of possible CaSO4(s) was detected by continuing the flooding with DI water at 130 °C even after 4 PV (Figure 12). As mentioned previously, the test at 130 °C was repeated and the temperature was decreased to 20 °C and kept at this temperature for 3 days after extractable sulfate was removed at high temperatures. DI water was injected, and the effluent at room temperature was also analyzed for SO42, Mg2+, and Ca2+. When the temperature was decreased, a new equilibrium between the rock and brine was established, confirming the presence of CaSO4(s) (Figure 13). The shape of the sulfate effluent curve at room temperature was similar to the effluent curve at 130 °C (Figure 12). The total amount of recovered SO42 at room temperature was equal to produced Ca2+ (≈0.016 mmol), as shown by Figures 13 and 14. This corresponded to 1.45 mg of SO42, and when this was added to the recovered amount of sulfate at 130 °C (2.9 mg; Table 2), we obtain 4.4 mg, which is close to the recoverable amount at 20 and 50 °C. Thus, precipitated CaSO4(s) at high temperatures was dissolved at room temperature. No detectable amount of Mg2+ was
Figure 14. Concentration of Ca2+ in the effluent of the core aged in 0.1VB-6S at 130 °C and then in DI water at Troom when flooded with DI water. Injection rate = 0.2 mL/min.
produced when the temperature was reduced to room temperature, confirming irreversible retention of Mg2+ in the core. For a given amount of sulfate initially present in the formation water, the wetting properties and possible oil recovery by spontaneous imbibition without wettability alteration appeared to be dictated by the amount of sulfate dissolved in the pore water, i.e., the concentration of SO42(aq). At low temperatures, the concentration of SO42(aq) is high, and as shown by the wettability test and oil recovery by spontaneous imbibition, the chalk was more water-wet. At high temperatures, the concentration of SO42(aq) is decreased because of the precipitation of sulfate and the chalk surface appeared less water-wet. This is indicated by the linear relationship between oil recovery from the cores containing VB-2S as formation water and the extractable fraction of SO42(aq), even though the formation brine with a higher concentration of sulfate was 10 times diluted (0.1VB-6S) compared to the formation brine in the imbibition tests (Figure 15). This is also in line with the impact of sulfate as a catalyst in the wettability alteration mechanism using seawater as discussed later.6 Even though the sulfate equilibrium in the porous medium was studied in a core material not previously exposed to crude oil, it is assumed that the equilibrium between SO42(aq) and SO42(ad) 3026
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Figure 15. Linear relationship between oil recovery from the cores containing VB-2S as formation water and the fraction of SO42(aq) in the extracted sulfate.
Figure 16. Concentration of Mg2+ in the effluent of the core aged in 0.1VB-6S at different temperatures when flooded with DI water. Injection rate = 0.2 mL/min.
is established at the water sites of the rock surface, in line with the principles of the chromatographic wettability test.9 Impact of Mg2+ and Ca2+ on the RockFluid Interaction. In addition to sulfate, the effluent was also analyzed for Mg2+ and Ca2+ when the cores were flooded with DI water after 3 days of aging at elevated temperatures. The concentration of Mg2+ and Ca2+ in the effluent was plotted against injected volume (Figures 16 and 17). In previous work using seawater, it has been observed that Mg2+ is able to substitute Ca2+ on the chalk surface in a 1:1 reaction, possibly in the Stern layer.6 In the case of Mg2+, the concentration in the pore water was also significantly lower than in the initial fluid and the concentration decreased drastically as the temperature increased (Figure 16). The effluent concentration profile was different from sulfate, and no concentration peak linked to desorption of Mg2+ was observed. Furthermore, no Mg2+ was recovered in additional tests at 130 °C after decreasing the temperature to room temperature. Because the initial concentration of Ca2+ ≈ 4Mg2+ in the VB-6S brine, it is difficult to verify that the molar decrease in the Mg2+ concentration corresponded to the same molar increase in Ca2+ (Figure 17). Connection between Wettability Alteration and Initial Wetting. Water-based enhanced oil recovery (EOR) in carbonates involving wettability alteration is becoming a very important issue. The presence of sulfate appeared to be the key parameter for the wettability alteration process to take place. Experimental
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Figure 17. Concentration of Ca2+ in the effluent of the core aged in 0.1VB-6S at different temperatures when flooded with DI water. Injection rate = 0.2 mL/min.
studies have shown that sulfate present in the injected fluid will adsorb onto the positively charged carbonate rock, which will initiate an increased excess of Ca2+ close to the surface. Ca2+ can then react/bind with the carboxylic group, RCOO, and the complex is removed from the surface.1 The concentration of sulfate at the injected/imbibed water front is crucial for the efficiency of the process. As the injected water invades into the porous medium, the concentration of sulfate in the front will decrease because of adsorption and possible precipitation of CaSO4(s). Anhydrite, which is often present in carbonate reservoirs, has an impact on the initial wetting condition, which is related to the established equilibrium between SO42(aq), SO42(ad), and CaSO4(s) (eq 1) at the actual reservoir conditions. Injection/imbibing fluid with a completely different composition compared to formation water composition can change the equilibrium, and the concentration of SO42(aq) can increase because of enhanced dissolution of CaSO4(s). In that way, anhydrite may act as an in situ source of sulfate and the water front will not be depleted in sulfate. Research on this topic is in progress in our laboratory.
’ CONCLUSION In the same way as sulfate is a key parameter in the wettability alteration process using seawater as an EOR fluid in mixed wet carbonates, even small amounts of sulfate present in the formation water can have great effects on the initial wetting condition for a carbonate reservoir. The effect of sulfate on the initial wetting properties has been experimentally verified by (1) studying the rockfluid interaction at different temperatures (20130 °C) using formation water with small amounts of sulfate in chalk cores, (2) performing spontaneous imbibitions into mixed wet chalk, and (3) verifying different wetting conditions by chromatographic wettability tests. The main conclusions from the work are summarized as follows: (1) An experimental technique was worked out to quantify the amount of sulfate present in the pore water, SO42(aq), and the extractable amount adsorbed onto the rock, SO42(ad), at different temperatures. (2) For a given concentration of sulfate, the amount of SO42(aq) decreased, while SO42(ad) remained quite constant as the temperature increased above 50 °C because of precipitation of CaSO4(s). Below 50 °C, the relative amount of SO42(aq) and SO42(ad) was quite constant. (3) For the different aging temperatures of 50, 90, and 130 °C, the oil recovery by spontaneous imbibition at 50 °C increased as the amount of sulfate in the formation water increased to 2 mmol/L. A higher concentration of sulfate in the 3027
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Energy & Fuels formation water did not improve the water-wetness of the rock, and the oil recovery was unaffected. (4) Chromatographic wettability tests confirmed that the cores containing sulfate in the formation water became more water-wet than cores without sulfate present in the formation water at all of the tested temperatures. The waterwet fraction increased as the aging temperature decreased. (5) In line with the previously proposed mechanism for wettability alteration in carbonates by seawater, sulfate dissolved in the pore water, SO42(aq), appeared to be the active species preventing adsorption of carboxylic material onto the rock surface.
’ AUTHOR INFORMATION Corresponding Author
*E-mail:
[email protected].
’ ACKNOWLEDGMENT The authors acknowledge BP for the financial support of this work and for the permission to publish this paper.
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(5) Puntervold, T.; Strand, S.; Austad, T. New method to prepare outcrop chalk cores for wettability and oil recovery studies at low initial water saturation. Energy Fuels 2007, 21 (6), 3425–3430. (6) Zhang, P.; Austad, T. Wettability and oil recovery from carbonates: Effects of temperature and potential determining ions. Colloids Surf., A 2006, 279, 179–187. (7) Zhang, P.; Austad, T. The relative effects of acid number and temperature on chalk wettability. Proceedings of the Society of Petroleum Engineers (SPE) International Symposium on Oilfield Chemistry; The Woodlands, TX, Feb 24, 2005; SPE Paper 92999, pp 185191. (8) Springer, N.; Korsbech, U.; Aage, H. K. Resistivity index measurement without the porous plate: A desaturation technique based on evaporation produces uniform water saturation profiles and more reliable results for tight North Sea chalk. Proceedings of the International Symposium of the Society of Core Analysts; Pau, France, Sept 2124, 2003. (9) Strand, S.; Standnes, D. C.; Austad, T. New wettability test for chalk based on chromatographic separation of SCN and SO42. J. Pet. Sci. Eng. 2006, 52, 187–197.
’ NOMENCLATURE Awet = adsorption area, the area between the tracer and sulfate in the chromatographic wettability test for the actual system Aref = adsorption area, the area between the tracer and sulfate in the chromatographic wettability test for a strongly waterwet reference sample AN = acid number (mg of KOH/g) BN = base number (mg of KOH/g) DI = deionized IS = ionic strength (mol/L) OOIP = original oil in place (mL) PV = pore volume (mL) SK = Stevns Klint SO42(ad) = sulfate dissolved in pore water SO42(ad) = sulfate adsorbed onto the rock surface SW1/2T = seawater where the concentration of SCN and SO42 is 12 mmol/L SW0T = seawater without SO42 TDS = total dissolved solids (g/L) VB-0S = formation water free from sulfate VB-2S = formation water containing 2 mmol/L sulfate VB-6S = formation water containing 6 mmol/L sulfate VB-17S = formation water containing 17 mmol/L sulfate 0.1VB-2S = 10 times diluted VB-2S 0.1VB-6S = 10 times diluted VB-6S 0.1VB-17S = 10 times diluted VB-17S WI = water-wet fraction of the surface area ’ REFERENCES (1) Zhang, P.; Tweheyo, M. T.; Austad, T. Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk: Impact of the potential determining ions: Ca2+, Mg2+ and SO42. Colloids Surf., A 2007, 301, 199–208. (2) Strand, S.; Høgnesen, E. J.; Austad, T. Wettability alteration of carbonates—Effects of potential determining ions (Ca2+ and SO42) and temperature. Colloids Surf., A 2006, 275, 1–10. (3) Zhang, P.; Tweheyo, M. T.; Austad, T. Wettability alteration and improved oil recovery in chalk: The effect of calcium in the presence of sulfate. Energy Fuels 2006, 20, 2056–2062. (4) Fathi, S. J.; Austad, T.; Strand, S. “Smart water” as wettability modifier in chalk: The effect of salinity and ionic composition. Energy Fuels 2010, 24 (4), 2514–2519. 3028
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