Article pubs.acs.org/EF
Water Based EOR by Wettability Alteration in Dolomite S. F. Shariatpanahi, P. Hopkins, H. Aksulu, S. Strand, T. Puntervold,* and T. Austad Petroleum Technology Institute, University of Stavanger, 4036 Stavanger, Norway ABSTRACT: Water based oil recovery from carbonates is a great challenge due to unfavorable wetting properties. Especially in naturally fractured formations, when spontaneous imbibition is an important drive mechanism, the oil recovery is low. In the past decade, much scientific work has been published focusing on the chemical understanding of wetting properties in chalk and limestone. Very little systematic work has been addressed to dolomite, which is also an important reservoir rock in the carbonate family. Recent work has shown that seawater acts as a Smart Water wettability modifier in calcite at higher temperatures due to symbiotic interaction between Ca2+, Mg2+, and SO42− and the rock surface. In the present work, the affinity of these active components toward the dolomite surface is discussed and compared to previous experimental work in calcite. The affinity of sulfate toward the carbonate surface, which is the catalyst for the wettability alteration process, was very low toward dolomite. Spontaneous imbibition studies confirmed that seawater was not a good wettability modifier in dolomite at 70 °C. Using 10 times diluted seawater as imbibing brine increased oil recovery due to wettability alteration by 15% of OOIP compared to ordinary seawater. No extra oil was recovered by using 100 times diluted formation water without sulfate as imbibing fluid, confirming that the low salinity brine must contain some sulfate as catalyst to achieve wettability alteration.
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INTRODUCTION In high temperature carbonate oil reservoirs, seawater, SW, could act as a smart EOR fluid because it is able to change wetting properties of the rock toward more water wet conditions. The positive capillary forces are increased, which are important for oil recovery, especially in naturally fractured reservoirs. The wettability alteration effect has been observed both in chalk and reservoir limestone cores.1−4 Intensive laboratory studies during the past decade have confirmed that a symbiotic interaction between active potential determining ions in seawater (Ca2+, Mg2+, and SO42−) at the calcite surface is able to release some adsorbed carboxylic material from the positively charged rock surface.2,4 Sulfate acts as a catalyst for the wettability alteration process because it adsorbs onto the carbonate surface. A reduced positive surface charge promotes coadoption of Ca2+ to the surface, which reacts with the adsorbed carboxylic group. At high temperatures, Tres > 70 °C, Mg2+ is able to substitute Ca 2+ and increase the Ca 2+ concentration close to the carbonate surface. It must be noticed that also two different outcrop limestone formations have been tested. In both cases, the outcrop samples showed negligible affinity toward sulfate ions even at high temperature, and no EOR effect was observed using seawater as wettability modifier.5 Seawater as a Smart Water can even be improved by removing Na+ and Cl−, which are nonactive ions in the wettability alteration process. The oil recovery was increased by 10% of OOIP compared to ordinary SW at 90 °C. This cannot be explained as a low salinity EOR effect, because just dilution of SW will decrease the oil recovery due to the decrease in the concentration of active ions (Ca2+, Mg2+, and SO42−).6,7 If, however, the formation contains dissolvable anhydrite, CaSO4, which is common in evaporates, LS EOR effects can be observed.8,9 In this case, the catalyst for the wettability alteration process, SO4 2−, is stored in the formation. Dissolution of anhydrite increases as the salinity of the injected © 2016 American Chemical Society
brine decreases. Furthermore, as mentioned above, low concentration of NaCl has a positive effect on the efficiency of the wettability alteration process. About half of the proven oil resources are present in carbonates, and, in that case, dolomite is also an important reservoir rock. From a chemical point of view, the surface reactivity of dolomite toward the active ions in seawater, Ca2+, Mg2+, and SO42− and toward carboxylic material present in the crude oil must be different from that of the calcite surface. It is well-known that dolomite reservoir rock often behaves preferentially oil wet.10 Up to now, no systematic chemical studies on Smart Water EOR effects in dolomite have been published. Therefore, the following question will be addressed in this experimental work: ”Will Seawater or modif ied Seawater act as a Smart EOR f luid also in preferential oil-wet dolomite?” The following test program was performed: − The role of Ca2+ and Mg2+ in the formation water on the initial wetting of chalk was tested selectively. It has previously been reported that the presence of SO42− in the formation water improved the water wetness slightly.11,12 − The affinity of SO42− toward the dolomite surface was tested chromatographically at low and high temperature using outcrop core material. − Oil recovery tests by spontaneous imbibition from two outcrop dolomite cores by successively using FW, SW, and 10 times diluted SW as imbibing fluids were performed.
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EXPERIMENTAL SECTION
Brines. Synthetic brines were prepared by dissolving specific amount of salts in deionized (DI) water. Prior to use, all brines were filtered through a 0.22 μm Millipore filter. Received: September 28, 2015 Revised: December 9, 2015 Published: January 5, 2016 180
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Article
Energy & Fuels Table 1. Compositions of Brines Used in Oil Recovery Experiments on SK Chalk Cores ions
CaCl2 (I), mM
CaCl2 (II), mM
CaCl2 (III), mM
NaCl, mM
MgCl2 (I), mM
MgCl2 (II), mM
MgCl2 (III), mM
VB0S, mM
HCO3− Cl− SO42− SCN− Mg2+ Ca2+ Na+ K+ TDS, g/L IS, mol/L
0 1132 0 0 0 566 0 0 62.83 1.698
0 1104 0 0 0 283 538 0 62.83 1.387
0 1080 0 0 0 46 987 0 62.83 1.126
0 1075 0 0 0 0 1075 0 62.83 1.075
0 1320 0 0 660 0 0 0 62.83 1.980
0 1197 0 0 330 0 538 0 62.83 1.527
0 1095 0 0 54 0 987 0 62.83 1.149
0 1081 0 0 8 0 1008 0 62.83 1.118
For the initial wettability experiments on the chalk cores, brines with different concentration of cations (Ca2+, Mg2+, and Na+) and with a constant salinity of 62.83 g/L were used, comparable to the Valhall formation brine, VB0S. The brine terminology and composition are listed in Table 1. In the oil recovery tests from the dolomite cores, the brines termed Formation Water (FW), Seawater (SW), and 10 times diluted SW (d10SW) were used. The brine terminology and composition is listed in Table 2.
mD and 45−50%, respectively. The BET surface area of the chalk was 1.70 m2/g, measured by MCA Service, UK. Chalk cores, SK, were oversized drilled in the same direction from a single outcrop block, shaved to a dimension of 3.80 cm in diameter, and cut to a length of 7.00 cm. The Silurian outcrop dolomite cores, SIL, were received from Shell. The permeability ranged from 201 to 235 mD, and the porosity was about 20%, Table 5. Initial Core Preparation. The outcrop cores were initially flooded at ambient temperature with 10 PVs deionized (DI) water at a rate of 0.1 mL/min to remove easily dissolvable salts, especially sulfate. The presence of sulfate in the effluent was confirmed in a batch test, by adding Ba2+ ions to a small effluent sample and visually detect possible precipitation of BaSO4 (s). During DI flooding of SIL#7, effluent samples were collected, and the concentration of Ca2+, Mg2+, and SO42− was analyzed. Ion concentrations in milli Molar, mM, are presented as a function of PVs injected. All cores were dried at 90 °C to constant weight prior to any experiments. Chromatographic Surface Reactivity Test. The affinity of sulfate toward the dolomite rock surface was tested chromatographically using a Hassler core holder.13 A SIL core was initially equilibrated with SW without SO42− and tracer, SCN− (SW0T) at a constant injection rate of 0.1 mL/min. Then the core was successively flooded with SW containing sulfate and tracer (SW1/2T). The chromatographic separation between the tracer and sulfate was monitored by plotting the relative ion concentrations in the effluent samples vs PV injected. The area between the tracer and sulfate curves, Aw, was calculated and compared with the value obtained for a completely water-wet rock surface. When sulfate adsorbs onto the calcite surface, a coadsorption of Ca2+ has previously been experimentally observed, due to a decrease in electrostatic repulsion.4 The effluent was also analyzed for Ca2+ and Mg2+ ions. The test on Dolomite was performed at two different temperatures, 20 and 130 °C. The influence of NaCl on the sulfate adsorption was also investigated by reducing the NaCl concentration in the test brines. All the brines used in the chromatographic tests are listed in Table 3.
Table 2. Compositions of Brines Used in Oil Recovery Tests in SIL Outcrop Dolomite Cores ions
FW, mM
SW, mM
d10SW, mM
HCO3− Cl− SO42− SCN− Mg2+ Ca2+ Na+ K+ TDS, g/L IS, mol/L
1 3867 2 0 92 414 2849 13 222.19 4.379
2 526 24 0 45 13 450 10 33.43 0.657
0.2 5.3 2.4 0 4.5 1.3 45.0 1 3.34 0.066
In surface reactivity tests of sulfate, the chemical properties of the brines are listed in Table 3. Oils. Three different stabilized crude oils with different acid numbers, AN, were used. Oil 1 and Oil 2 were used for the initial wettability tests in chalk. Oil 3 was used in oil recovery tests in outcrop dolomite cores. The oil samples were centrifuged and filtered through a 5 μm Millipore filter prior to use. Chemical and physical oil properties are given in Table 4. Core Material. Stevns Klint outcrop chalk has been used in this study, originating from nearby Copenhagen, Denmark. This chalk is very homogeneous with permeability and porosity in the range of 1−3
Table 3. Compositions of Brines Used in Chromatographic Sulfate Reactivity Tests in SIL Outcrop Dolomite Cores ions +
Na Li+ Ca2+ Mg2+ K+ Ba2+ Cl− SO42− HCO3− TDS, g/L IS mol/L
SW0T, mM
SW1/2T, mM
SW0T10Na, mM
SW1/4T10Na, mM
SW0T50Na, mM
SW1/4T50Na, mM
460.4 0.0 13.0 44.5 10.1 0.0 583.5 0.0 2.0 33.39 0.643
426.6 12.0 13.0 44.5 22.1 0.0 537.6 12.0 2.0 33.39 0.645
42.0 0.0 13.0 44.5 10.1 0.0 165.1 0.0 2.0 8.94 0.225
54.0 6.0 13.0 44.5 16.1 0.0 171.1 6.0 2.0 10.63 0.255
202.1 0.0 13.0 44.5 10.1 0.0 325.1 0.0 2.0 18.29 0.385
214.1 6.0 13.0 44.5 16.1 0.0 331.1 6.0 2.0 19.98 0.415
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Energy & Fuels Table 4. Oil Properties of Crude Oils Used in Oil Recovery Tests AN, mg KOH/g
BN, mg KOH/g
asphaltene, g/100 mL
density, g/cm3 @20 °C
viscosity, mPas @20 °C
0.34 0.17 0.52
0.2 0.1 1.0
DI-water. It is interesting to note that the lowest water wetness was observed for DI water. The lack of ionic double layer outside the chalk surface probably 183
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concentration of Ca2+ and Mg2+ remained quite constant and equal, pointing to dolomite dissolution. Therefore, all dolomite cores prepared for oil recovery tests were initially flooded with DI water, about 10 PV, to remove traces of anhydrite. After the initial test for anhydrite, the outcrop core SIL#7 was tested for capillary forces by spontaneous imbibition of DI water at room temperature. The core was saturated with 100% heptane saturation and with 90% heptane and Swi equal 10%. In both cases, the core behaved water wet, and close to 30% of the heptane was recovered confirming the presence of reasonably strong capillary forces even in a inhomogeneous dolomitic rock, Figure 6.
makes it easier for the carboxylic anchor molecules to break the water film. The present observations are in line with the work by Gomari et al. (2006), who showed that the adsorption of fatty acids onto the calcite surface can be decreased by increasing the Mg2+ concentration in the formation brine.20,21 As a conclusion, the presence of Mg2+ in the formation water appears to make the carbonate surface more water wet due to adsorption onto the rock surface. This indicates a weaker bonding of carboxylic material onto the carbonate surface. By drawing a relation to the dolomite surface, a relevant question is “Is the adsorption of acidic material in the crude oil onto dolomite weaker than for calcite, and if that is the case, is it easier to change wetting properties of dolomite compared to calcite?”. This will be discussed in the next section using outcrop dolomite cores. Wettability Alteration in Dolomite Cores. There is no reason to believe that the chemical mechanism for wettability modification with smart water in dolomite should be different compared to other carbonates. Therefore, the same standard experimental procedure was chosen as normally used for limestone core material: − Checking for the presence of anhydrite, CaSO4, in the core material. − Confirming capillary forces of the water wet rock. − Chromatographic test of the affinity of SO42− toward the rock surface and possible change in the concentration of Ca2+ and Mg2+ as sulfate enters the porous medium at low and high temperature. − Oil recovery tests by spontaneous imbibition at 70 °C, using different brines. As discussed previously, sulfate is the key ion in the Smart Water EOR process, and it has also impact on the initial wetting as well as acting as the catalyst for the wettability modification. It is therefore important to verify if anhydrite is part of the rock matrix. Note that an XRD analysis is not sensitive enough to verify traces of anhydrite. Core SIL#7 was therefore flooded with DI water at room temperature, and the effluent was analyzed for Ca2+, Mg2+, and SO42− using an ion chromatograph, Figure 5. The concentration of sulfate initially eluted from the core amounted to 0.3 mM, and it decreased rapidly to below 0.001 mM. It was noticed that the peak in the SO42− concentration corresponded to the small peak in the Ca2+ concentration, indicating the presence of a very small amount of dissolvable anhydrite in the pore system. The
Figure 6. Spontaneous imbibition of DI water into heptane saturated dolomite core SIL#7 without and with initial water saturation of Swi = 0.10 at 20 °C.
The key step for the wettability alteration with Smart Water in calcite is the adsorption of SO42− onto the carbonate surface. It has been verified that the adsorption increases as the temperature increased.4 The affinity of sulfate toward the dolomitic surface was tested chromatographically. First the core was equilibrated with SW0T, a modified seawater brine without SO42− and tracer, SCN−, and then flooded with SW1/2T containing SO42− and SCN− in equal concentration. The concentration of SO42−, SCN−, Ca2+, and Mg2+ was measured in effluent samples. The chromatographic separation between the tracer and sulfate for the SIL#7 core is shown in Figure 7. The adsorption of sulfate onto dolomite at room temperature is low, with an adsorption area between the tracer and sulfate curve of Aw = 0.08. At 130 °C, the sulfate adsorption increased to Aw = 0.16. These values are small compared to previous observations for chalk and reservoir limestone cores showing Smart Water EOR effects.3,6,7,13,22−24 The change in the Ca2+ and Mg2+ concentration as sulfate enters the core is small, confirming that the presence of SO42− has negligible effects on coadsorption/desorption of Ca2+ and Mg2+ from the dolomitic surface, Figure 8. This is also quite different from a reactive calcite surface.4,25,26 Thus, based on these preliminary tests and previous observations in calcite, SW should not be an optimum Smart Water for wettability alteration in dolomite. Oil recovery tests by spontaneous imbibition were conducted on two dolomite cores, SIL#9 and SIL#6, at 70 °C. Both outcrop cores were restored using initial water saturation of 15% with formation water (FW), saturated and aged with Oil 3. The restored cores were successively imbibed with FW, seawater (SW), and 10 times diluted seawater (d10SW), Figure
Figure 5. Core SIL#7 was flooded at 20 °C with DI water with a rate of 0.1 mL/min. Sulfate, calcium, and magnesium content in effluent samples were analyzed and presented vs PV injected. 184
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recovery increased dramatically to 25% of OOIP. The corresponding values for core SIL#6 were 6, 7, and 16% of OOIP, respectively. Thus, in line with the results from the preliminary tests, SW is not an efficient smart EOR fluid in dolomite. However, the oil recovery was improved drastically when SW was diluted 10 times. In limestone, low salinity EOR effects have been observed in a forced displacement process provided that the rock contains dissolvable anhydrite, CaSO4 (s).8,9 For the dolomite cores used in this study, anhydrite was not present. We may then ask: “Is the improved oil recovery by d10SW (salinity of 3339 ppm) an ef fect only linked to the salinity of the imbibing f luid or is the composition of the low saline f luid important, like the presence of sulfate?”. If only salinity is important, diluted FW should also give a similar effect on oil recovery in a tertiary imbibition process. Therefore, two new oil recovery tests were performed by preparing the cores SIL#7 and SIL#4 in the same manner as before. The cores were imbibed with FW followed 100 times diluted FW, d100FW (salinity of 2222 ppm) at 70 °C, and no extra oil was recovered when switching from FW to diluted FW. The amount of SO42− in the FW was very low, only 2 mM, Table 1. In reality, d100FW is nearly free from SO42−, and the salinity is more than 1000 ppm lower than in d10SW. From a compositional point of view, the main difference between d10SW and d100FW is the presence of SO42−, 2.4 and 0.02 mM, respectively. Previous laboratory tests using reservoir cores of Dolostone with varying amounts of anhydrite showed similar effects on oil recovery by spontaneous imbibition at 85 °C.27 Spontaneous imbibition studies using a high salinity formation brine, 230 770 ppm, resulted in oil recoveries in the range of 2−10% of OOIP. By switching to a LS brine with a salinity of 4930 ppm and containing only 1 mM SO42−, the oil recovery was increased by 3−20%OOIP. It was confirmed by compositional analysis that anhydrite was dissolved during the LS imbibition process, and the concentration of SO42− in the surrounding imbibing fluid was increased to 2−10 mM. There was, however, no direct correlation between the amount of anhydrite dissolved and ultimate oil recovery. As for the present outcrop dolomite core material, incremental oil recovery due to wettability alteration was observed also in the absence of significant dissolution of anhydrite. Contrary to previous observations in limestone, it is interesting to observe that reservoir cores used in the study by Romanuka et al.27 and outcrop dolomite cores responded in a similar way regarding oil recovery by wettability alteration. As a preliminary observation based on results from this work and previous published work on chalk and limestone, it appears that SO42− is still acting as a catalyst for wettability alteration in slightly water wet dolomite at higher temperatures. Due to a lower affinity of sulfate toward the dolomite surface compared to calcite, the salinity of the Smart Water brine should be low to increase the surface reactivity of sulfate and calcium ions to improve the chemical wettability alteration process. No significant difference in the affinity of sulfate toward the dolomite surface was detected in chromatographic surface reactivity tests on dolomite core, using SW1/4T brine containing 10 and 50% of NaCl present in SW, Figure 10 a and b. The calculated adsorption area, Aw, was 0.158 and 0.153, respectively.
Figure 7. Surface reactivity test on outcrop dolomite rock. The core SIL#7 was equilibrated with SW0T prior to SW1/2T injection at a rate of 0.1 mL/min. The affinity of SO42− toward the rock surface was chromatically verified at 20 and 130 °C.
Figure 8. Relative concentrations of Ca2+ and Mg2+ in effluent during the surface reactivity test on core SIL#7 at 20 and 130 °C using SW.
9. Although the oil recovery responded differently for the two cores, the trend was the same. About 8% of OOIP was recovered during imbibition of FW imbibition for SIL#9. The oil recovery increased only to 11% of OOIP when the imbibing fluid was changed to SW. After switching to d10SW, the oil
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Figure 9. Oil recovery from dolomite cores SIL#6 and SIL#9 by using FW, Swi = 0.15; salinity 222 000 ppm, as formation water. Oil 3 with AN = 0.52 mgKOH/g was used. The cores were spontaneously imbibed at 70 °C, with FW, SW, and d10SW.
CONCLUSIONS Water based oil recovery in a spontaneous imbibition process from dolomite outcrop cores by wettability alteration has been 185
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Figure 10. Chromatographic separation between the tracer, SCN−, and SO42−, when flooding the dolomite core SIL#7 at 20 °C with SW0T continued by SW1/4T containing, (a) 10% and (b) 50% of NaCl initially present in SW. Calculated area of separation is ∼0.15 in both cases. (7) Fathi, S. J.; Austad, T.; Strand, S. Energy Fuels 2011, 25, 5173− 5179. (8) Austad, T.; Shariatpanahi, S. F.; Strand, S.; Black, C. J. J.; Webb, K. J. Energy Fuels 2012, 26 (1), 569−575. (9) Yousef, A. A.; Al-Saleh, S.; Al-Jawfi, M. S. In Improved/enhanced oil recovery from carbonate reservoirs by tuning injection water salinity and ionic content, Paper SPE 154076 presented at the Eighteenth SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, 14−18 April, 2012. (10) Standnes, D. C.; Nogaret, L. A. D.; Chen, H.-L.; Austad, T. Energy Fuels 2002, 16 (6), 1557−1564. (11) Shariatpanahi, S. F.; Strand, S.; Austad, T. Energy Fuels 2011, 25 (7), 3021−3028. (12) Puntervold, T.; Strand, S.; Austad, T. Energy Fuels 2007, 21 (6), 3425−3430. (13) Strand, S.; Standnes, D. C.; Austad, T. J. Pet. Sci. Eng. 2006, 52, 187−197. (14) Fan, T.; Buckley, J. SPE Journal 2007, December. (15) Fan, T.; Buckley, J. Base number titration of crude oil samples. Personal communication: 2000. (16) Springer, N.; Korsbech, U.; Aage, H. K. In 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, Paper presented at the International Symposium of the Society of Core Analysts Pau, France, 21−24 Sept, 2003. (17) Puntervold, T.; Strand, S.; Austad, T. Energy Fuels 2007, 21 (3), 1606−1616. (18) Standnes, D. C.; Austad, T. J. Pet. Sci. Eng. 2000, 28 (3), 111− 121. (19) Qiao, C.; Li, L.; Johns, R. T.; Xu, J. In A mechanistic model for wettability alteration by chemically tuned water flooding in carbonate reservoirs, Paper SPE 170966 presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, 27−29 October, 2014. (20) Gomari, K. A. R.; Hamouda, A. A. J. Pet. Sci. Eng. 2006, 50 (2), 140−150. (21) Gomari, K. A. R.; Hamouda, A. A.; Denoyel, R. Colloids Surf., A 2006, 287 (1−3), 29−35. (22) Shariatpanahi, S. F.; Strand, S.; Austad, T.; Aksulu, H. Pet. Sci. Technol. 2012, 30, 1082−1090. (23) Ravari, R. R.; Austad, T.; Strand, S. In Water-based EOR from a low permeable fractured limestone by wettability alteration, 16th European Symposium on Improved Oil Recovery, Cambridge, UK, 12−14 April, 2011. (24) Strand, S.; Austad, T.; Puntervold, T.; Høgnesen, E. J.; Olsen, M.; Barstad, S. M. F. Energy Fuels 2008, 22, 3126−3133. (25) Austad, T. Water based EOR in carbonates and sandstones: new chemical understanding of the EOR potential using “Smart Water”. In Enhanced Oil Recovery Field Case Studies; Sheng, J. J., Ed.; Elsevier: Oxford, UK, 2013.
studied and discussed in relation to previous work in chalk and limestone. The conclusions from this work can shortly be summarized in the following way: • The presence of Mg2+ in the formation water appeared to increase the water wetness of calcite compared to Ca2+ due to adsorption onto the rock surface. Knowing that the dolomite surface contains both Mg2+ and Ca2+ as positively charged sites, it is reasonable to believe that the adsorption of active polar carboxylic material onto dolomite is weaker than for calcite. • Seawater is a smart EOR fluid in calcite at high temperature due to the strong affinity of SO42− toward the surface. The affinity of SO42− in SW toward the dolomite surface was low, and SW acted as a poor wettability modifier at 70 °C. • Incremental oil of 10−15% of OOIP was observed in a spontaneous imbibition process into outcrop dolomite cores when switching from SW to 10× diluted SW at 70 °C. • Contrary to outcrop limestone, outcrop dolomite appeared to respond to smart water in the same way as reservoir dolomite cores.
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors wish to acknowledge BP Sunbury for financial support. The authors also appreciate Julia Romanuka, Shell, for supplying the outcrop dolomite samples and for financial support.
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REFERENCES
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