Abstract
The effect of wettability on waterflooding oil recovery and the associated pore-scale displacement mechanisms are systematically investigated during flow processes in limestone core samples with a broad spectrum of wettability. Using a miniature core-flooding setup integrated with micro-computed tomography (CT) imaging apparatus, we, for the first time, characterize in situ equilibrium wettability states and demonstrate capillary interactions of the flowing phases in strongly water-wet (SWW), intermediate-wet (IW), weakly oil-wet (WOW), and strongly oil-wet (SOW) systems. The microscale observations were then employed to explain the recovery results obtained from replicate, macroscale experiments. The waterflooding parameters, such as experimental temperature, brine composition, defending and invading phase properties, and the initial water saturation, were maintained nearly identical in all of the waterflooding tests, thereby ensuring that the wettability state was the only factor that controlled the variations in waterflood oil recoveries. We provide pore-scale evidences of various pore-scale displacement mechanisms and the consequent fluid configurations in systems with different wettability states. These findings are then linked to the recovery trends of macroscale experiments. The production from IW, WOW, and SOW cases portrayed a prolonged oil recovery owing to the gradual invasion of brine into small and intermediate-sized oil-wet pores. The IW case showed the highest oil recovery among all cases. Moreover, when the injection flow rate was increased, the oil recovery was gradually increased for the IW, WOW, and SOW systems, whereas no significant additional production was observed in the case of SWW.
Similar content being viewed by others
References
Afekare, D.A., Radonjic, M.: From mineral surfaces and coreflood experiments to reservoir implementations: comprehensive review of low-salinity water flooding (LSWF). Energy Fuels 31, 13043–13062 (2017). https://doi.org/10.1021/acs.energyfuels.7b02730
Agbalaka, C., Dandekar, A.Y., Patil, S.L., Khataniar, S., Hemsath, J.R.: The effect of wettability on oil recovery: a review. SPE Asia Pacific Oil Gas Conf. Exhib. (2008). https://doi.org/10.2118/114496-MS
Al-Raoush, R.I.: Impact of wettability on pore-scale characteristics of residual nonaqueous phase liquids. Environ. Sci. Technol. 43, 4796–4801 (2009). https://doi.org/10.1021/es802566s
Alhammadi, A.M., AlRatrout, A., Bijeljic, B., Blunt, M.J.: In situ wettability measurement in a carbonate reservoir rock at high temperature and pressure. SPE Abu Dhabi Int. Pet. Exhib. Conf. (2017a). https://doi.org/10.2118/188510-MS
Alhammadi, A.M., Alratrout, A., Singh, K., Bijeljic, B., Blunt, M.J.: In situ characterization of mixed-wettability in a reservoir rock at subsurface conditions. Sci. Rep. 7, 1–9 (2017b). https://doi.org/10.1038/s41598-017-10992-w
Alizadeh, A.H., Khishvand, M., Ioannidis, M.A., Piri, M.: Multi-scale experimental study of carbonated water injection: an effective process for mobilization and recovery of trapped oil. Fuel 132, 219–235 (2014). https://doi.org/10.1016/j.fuel.2014.04.080
Amott, E.: Observations relating to the wettability of porous rock. Trans AIME. 216, 156–192 (1959)
Anderson, W.G.: Wettability Literature survey-part 6: the effects of wettability on waterflooding. J. Pet. Technol. 39, 1605–1622 (1987). https://doi.org/10.2118/16471-PA
Andrew, M., Bijeljic, B., Blunt, M.: Reservoir condition pore-scale imaging of multiple fluid phases using x-ray microtomography. J. vis. Exp. (2015). https://doi.org/10.3791/52440
Andrew, M., Bijeljic, B., Blunt, M.J.: Pore-scale contact angle measurements at reservoir conditions using X-ray microtomography. Adv. Water Resour. 68, 24–31 (2014). https://doi.org/10.1016/j.advwatres.2014.02.014
Benner, F.C.; Bartell, F.E.: The effect of polar impurities upon capillary and surface phenomena in petroleum production. In: Proceedings of the Drilling and Production Practice; (1941)
Blunt, M.J.: Multiphase Flow in Permeable Media: A Pore-Scale Perspective. Cambridge University Press (2017)
Blunt, M.J., Scher, H.: Pore-level modeling of wetting. Phys. Rev. E. 52, 6387–6403 (1995). https://doi.org/10.1103/PhysRevE.52.6387
Bonto, M., Eftekhari, A.A., Nick, H.M.: An overview of the oil-brine interfacial behavior and a new surface complexation model. Sci. Rep. 9, 6072 (2019). https://doi.org/10.1038/s41598-019-42505-2
Buades, A., Coll, B., Morel, J.-M.: A Non-Local Algorithm for Image Denoising. In: IEEE Computer Society Conference on Computer Vision and Pattern Recognition (CVPR’05). pp. 60–65. IEEE (2005)
Buckley, J.S., Liu, Y., Monsterleet, S.: Mechanisms of wetting alteration by crude oils. SPE J. 3, 54–61 (1998). https://doi.org/10.2118/37230-PA
Buckley, J.S., Takamura, K., Morrow, N.R.: Influence of electrical surface charges on the wetting properties of crude oils. SPE Reserv. Eng. 4, 332–340 (1989). https://doi.org/10.2118/16964-PA
Chang, Y.C., Mohanty, K.K., Huang, D.D., Honarpour, M.M.: The impact of wettability and core-scale heterogeneities on relative permeability. J. Pet. Sci. Eng. 18, 1–19 (1997). https://doi.org/10.1016/S0920-4105(97)00006-5
Christensen, M., Tanino, Y.: Waterflood oil recovery from mixed-wet limestone: dependence upon the contact angle. Energy Fuels 31, 1529–1535 (2017). https://doi.org/10.1021/acs.energyfuels.6b03249
Craig, F.: The reservoir engineering aspects of waterflooding. SPE Monogr. Ser. Dallas.TX (1971)
Dalton, L.E., Klise, K.A., Fuchs, S., Crandall, D., Goodman, A.: Methods to measure contact angles in scCO2-brine-sandstone systems. Adv. Water Resour. 122, 278–290 (2018). https://doi.org/10.1016/j.advwatres.2018.10.020
Dernaika, M., Masalmeh, S.: The effect of pore geometry on relative permeability in mixed-Wet carbonate reservoirs in abu dhabi. In: Abu dhabi international petroleum exhibition & conference. Soc. Petrol. Eng. (2019a)
Dernaika, M., Masalmeh, S.: The effect of pore geometry onrelative permeability in Mixed-Wet carbonate reservoirs in abu dhabi. In: Abu dhabi international petroleum exhibition & conference. Soc. Petrol. Eng. (2019b)
Donaldson, E.C., Thomas, R.D., Lorenz, P.B.: Wettability determination and its effect on recovery efficiency. Soc. Pet. Eng. J. 9, 13–20 (1969). https://doi.org/10.2118/2338-PA
Feldmann, F., AlSumaiti, A.M., Masalmeh, S.K., AlAmeri, W.S., Oedai, S.: Impact of brine composition and concentration on capillary pressure and residual oil saturation in limestone core samples. E3S Web Conf. 89, 02006 (2019). https://doi.org/10.1051/e3sconf/20198902006
Graue, A., Viksund, B.G., Baldwin, B.A.: Reproducible wettability alteration of low-permeable outcrop chalk. SPE Reserv. Eval. Eng. 2, 134–140 (1999). https://doi.org/10.2118/55904-PA
Hamouda, A.A., Rezaei Gomari, K.A.: Influence of temperature on wettability alteration of carbonate reservoirs. In: SPE/DOE symposium on improved oil recovery. Soc. Petrol. Eng. (2006)
Hirasaki, G., Zhang, D.L.: Surface chemistry of oil recovery from fractured, oil-wet. Carbonate Formations. SPE J. 9, 151–162 (2004). https://doi.org/10.2118/88365-PA
Ibekwe, A., Pokrajac, D., Tanino, Y.: Automated extraction of in situ contact angles from micro-computed tomography images of porous media. Comput. Geosci. 137, 104425 (2020). https://doi.org/10.1016/j.cageo.2020.104425
Iglauer, S., Fernø, M.A., Shearing, M.J.B.: Comparison of residual oil cluster size distribution, morphology and saturation in oil-wet and water-wet sandstone. J. Colloid Interface Sci. (2012)
Iglauer, S., Fernø, M.A., Shearing, P., Blunt, M.J.: Comparison of residual oil cluster size distribution, morphology and saturation in oil-wet and water-wet sandstone. J. Colloid Interface Sci. 375, 187–192 (2012). https://doi.org/10.1016/j.jcis.2012.02.025
Iglauer, S., Pentland, C.H., Busch, A.: CO 2 wettability of seal and reservoir rocks and the implications for carbon geo-sequestration. Water Resour. Res. 51, 729–774 (2015). https://doi.org/10.1002/2014WR015553
Jadhunandan, P.P., Morrow, N.R.: Effect of wettability on waterflood recovery for crude-oil/brine/rock systems. SPE Reserv. Eng. 10, 40–46 (1995). https://doi.org/10.2118/22597-PA
Kamath, J., Meyer, R.F., Nakagawa, F.M.: Understanding waterflood residual oil saturation of four carbonate rock types. In: SPE annual technical conference and exhibition. Soc. Petrol. Eng. (2001)
Karabakal, U., Bagci, S.: Determination of wettability and its effect on waterflood performance in limestone medium. Energy Fuels 18, 438–449 (2004). https://doi.org/10.1021/ef030002f
Khishvand, M., Alizadeh, A.H., Oraki Kohshour, I., Piri, M., Prasad, R.S.: In situ characterization of wettability alteration and displacement mechanisms governing recovery enhancement due to low-salinity waterflooding. Water Resour. Res. 53, 4427–4443 (2017). https://doi.org/10.1002/2016WR020191
Khishvand, M., Alizadeh, A.H., Piri, M.: In-situ characterization of wettability and pore-scale displacements during two- and three-phase flow in natural porous media. Adv. Water Resour. 97, 279–298 (2016). https://doi.org/10.1016/j.advwatres.2016.10.009
Khishvand, M., Oraki Kohshour, I., Alizadeh, A.H., Piri, M., Prasad, S.: A multi-scale experimental study of crude oil-brine-rock interactions and wettability alteration during low-salinity waterflooding. Fuel 250, 117–131 (2019). https://doi.org/10.1016/j.fuel.2019.02.019
Klise, K.A., Moriarty, D., Yoon, H., Karpyn, Z.: Automated contact angle estimation for three-dimensional X-ray microtomography data. Adv. Water Resour. 95, 152–160 (2016). https://doi.org/10.1016/j.advwatres.2015.11.006
Kovscek, A.R., Wong, H., Radke, C.J.: A pore-level scenario for the development of mixed wettability in oil reservoirs. AIChE j. 39, 1072–1085 (1993). https://doi.org/10.1002/aic.690390616
Kumar, M., Senden, T.J., Sheppard, A.P., Middleton, J.P., Knackstedt, M.A.: Visualizing and quantifying the residual phase distribution in core material. in: Int. Symp. Soc. Core Anal. Noordwijk, Netherlands, 27–30 Sept. 2009. SCA Paper 2009–16 (2009)
Kumar, N., Lawal, A.S.: A component based EOS for the compressibility factor of natural and sour gases. Presented at the (2009)
Kyte, J.R., Naumann, V.O., Mattax, C.C.: Effect of reservoir environment on water-oil displacements. J. Pet. Technol. 13, 579–582 (1961). https://doi.org/10.2118/55-PA
Lin, Q., Bijeljic, B., Berg, S., Pini, R., Blunt, M.J., Krevor, S.: Minimal surfaces in porous media: pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone. Phys. Rev. E. 99, 063105 (2019). https://doi.org/10.1103/PhysRevE.99.063105
Masalmeh, S., Al-Hammadi, M., Farzaneh, A., Sohrabi, M.: Low salinity water flooding in carbonate: Screening, laboratory quantification and field implementation. in: Abu dhabi international petroleum exhibition & conference. Soc. Petrol. Eng. (2019)
Masalmeh, S.K.: Studying the effect of wettability heterogeneity on the capillary pressure curves using the centrifuge technique. J. Pet. Sci. Eng. 33, 29–38 (2002). https://doi.org/10.1016/S0920-4105(01)00173-5
Masalmeh, S.K.: The effect of wettability on saturation functions and impact on carbonate reservoirs in the middle east. in: Abu dhabi international petroleum exhibition and conference. Soc. Petrol. Eng. (2002b)
Masalmeh, S.K.: The effect of wettability heterogeneity on capillary pressure and relative permeability. J. Pet. Sci. Eng. 39, 399–408 (2003). https://doi.org/10.1016/S0920-4105(03)00078-0
Melrose, J.C.: Role of capillary forces in detennining microscopic displacement efficiency for oil recovery by waterflooding. J. Can. Pet. Technol. (1974). https://doi.org/10.2118/74-04-05
Morrow, N.R.: Wettability and its effect on oil recovery. J. Pet. Technol. 42, 1476–1484 (1990). https://doi.org/10.2118/21621-PA
Morrow, N.R., Cram, P.J., McCaffery, F.G.: Displacement studies in dolomite with wettability control by octanoic acid. Soc. Pet. Eng. J. 13, 221–232 (1973). https://doi.org/10.2118/3993-PA
Morrow, N.R., Ma, S., Zhou, X., Zhang, X.: Characterization of wettability from spontaneous imbibition measurements. in: Annual technical meeting. Petrol. Soc. Canada. (1994)
Mungan, N.: Role of wettability and interfacial tension in water flooding. Soc. Pet. Eng. J. 4, 115–123 (1964). https://doi.org/10.2118/705-PA
Okasha, T.M., Funk, J.J., Rashidi, H.N.: Fifty Years of wettability measurements in the Arab-D carbonate reservoir. in: SPE middleeast oil and gas show and conference. Soc. Petrol. Eng. (2007)
Owens, W.W. & Archer, D..: The effect of rock wettability on oil-Water relative permeability relationships. J. Pet. Tech. 873–78, (1971)
Pickell, J.J., Swanson, B.F., Hickman, W.B.: Application of air-mercury and oil-air capillary pressure data in the study of pore structure and fluid distribution. Soc. Pet. Eng. J. 6, 55–61 (1966). https://doi.org/10.2118/1227-PA
Qin, Z., Arshadi, M., Piri, M.: Micro-scale experimental investigations of multiphase flow in oil-wet carbonates: I: in situ wettability and low-salinity waterflooding. Fuel 257, 116014 (2019). https://doi.org/10.1016/j.fuel.2019.116014
Rathmell, J.J., Braun, P.H., Perkins, T.K.: Reservoir waterflood residual oil saturation from laboratory tests. J. Pet. Technol. 25, 175–185 (1973). https://doi.org/10.2118/3785-PA
Rezaei Gomari, K.A., Denoyel, R., Hamouda, A.A.: Wettability of calcite and mica modified by different long-chain fatty acids (C18 acids). J. Colloid Interface Sci. 297, 470–479 (2006). https://doi.org/10.1016/j.jcis.2005.11.036
Salathiel, R.A.: Oil recovery by surface film drainage in mixed-wettability rocks. J. Pet. Technol. 25, 1216–1224 (1973). https://doi.org/10.2118/4104-PA
Schneider, F.N., Owens, W.W.: Relative permeability studies of gas-water flow following solvent injection in carbonate rocks. Soc. Pet. Eng. J. 16, 23–30 (1976). https://doi.org/10.2118/5554-PA
Singh, K., Bijeljic, B., Blunt, M.J.: Imaging of oil layers, curvature and contact angle in a mixed-wet and a water-wet carbonate rock. Water Resour. Res. 52, 1716–1728 (2016). https://doi.org/10.1002/2015WR018072
Sun, C., McClure, J.E., Mostaghimi, P., Herring, A.L., Meisenheimer, D.E., Wildenschild, D., Berg, S., Armstrong, R.T.: Characterization of wetting using topological principles. J. Colloid Interface Sci. 578, 106–115 (2020). https://doi.org/10.1016/j.jcis.2020.05.076
Takeya, M., Shimokawara, M., Elakneswaran, Y., Nawa, T., Takahashi, S.: Predicting the electrokinetic properties of the crude oil/brine interface for enhanced oil recovery in low salinity water flooding. Fuel 235, 822–831 (2019). https://doi.org/10.1016/j.fuel.2018.08.079
Tanino, Y., Blunt, M.J.: Capillary trapping in sandstones and carbonates: dependence on pore structure. Water Resour. Res. 48, 1–13 (2012). https://doi.org/10.1029/2011WR011712
Tetteh, J.T., Barati, R.: Crude-oil/brine interaction as a recovery mechanism for low-salinity waterflooding of carbonate reservoirs. SPE Reserv. Eval. Eng. 22, 0877–0896 (2019). https://doi.org/10.2118/194006-PA
Thomas, M.M., Clouse, J.A., Longo, J.M.: Adsorption of organic compounds on carbonate minerals. Chem. Geol. 109, 201–213 (1993). https://doi.org/10.1016/0009-2541(93)90070-Y
Treiber, L.E., Owens, W.W.: A laboratory evaluation of the wettability of fifty oil-producing reservoirs. Soc. Pet. Eng. J. 12, 531–540 (1972). https://doi.org/10.2118/3526-PA
Wagner, O.R., Leach, R.O.: Improving oil displacement efficiency by wettability adjustment. Trans. AIME. 216, 65–72 (1959). https://doi.org/10.2118/1101-G
Wang, Y., Masalmeh, S.K.: Obtaining High Quality SCAL Data: Combining different measurement techniques, saturation monitoring, numerical interpretation and continuous monitoring of experimental data. E3S Web Conf. 89, 02007 (2019). https://doi.org/10.1051/e3sconf/20198902007
Wildenschild, D., Sheppard, A.P.: X-ray imaging and analysis techniques for quantifying pore-scale structure and processes in subsurface porous medium systems. Adv. Water Resour. 51, 217–246 (2013). https://doi.org/10.1016/j.advwatres.2012.07.018
Witte, R., Witte, J.: Statistics. Wiley (2016)
Wu, Y., Shuler, P.J., Blanco, M., Tang, Y., Goddard, W.A.: An experimental study of wetting behavior and surfactant eor in carbonates with model compounds. SPE J. 13, 26–34 (2008). https://doi.org/10.2118/99612-PA
Xie Yun, Khishvand, Mahdi, Piri, M.: Impact of connate brine chemistry on in-situ wettability and oil recovery: A pore-scale experimental investigation. Energy & Fuels. (2020)
Acknowledgements
We gratefully acknowledge the financial support of Thermo Fisher Scientific, Hess Corporation, and the School of Energy Resources at the University of Wyoming. We also extend our gratitude to Uche Igwe, Binjuin Zhang, and Omar Elmasry of Piri Research Group at the Center of Innovation for Flow through Porous Media of the University of Wyoming for their assistance with the experimental setups and SEM image acquisition.
Author information
Authors and Affiliations
Contributions
GKE carried out conceptualization, methodology, investigation, data curation, formal analysis, writing the original draft, reviewing, and editing. MK took part in conceptualization, methodology, investigation, validation, writing reviewing, and editing. WK contributed to investigation, visualization, writing, reviewing, and editing. MP and SM were involved in conceptualization, supervision, writing, reviewing, and editing.
Corresponding author
Ethics declarations
Conflict of interest
The authors declare no conflict of interest.
Additional information
Publisher's Note
Springer Nature remains neutral with regard to jurisdictional claims in published maps and institutional affiliations.
Appendix
Appendix
More details of the experimental procedure are given in the following paragraphs:
-
1.
Initial preparation To initiate each experiment, each core sample was loaded inside a core holder and then vacuumed to remove bulk air from the pore space. Afterward, CO2 was injected into the core to displace the remaining air and the sample was vacuumed once more for at least 12 h to evacuate bulk CO2. At this stage, the middle section of each of the miniature core samples was imaged at a resolution of 2.7 µm (voxel size of 2.7 × 2.7 × 2.7 µm3) to obtain a dry reference scan and generate the pore map, which would be later employed to analyze images of the flooded sample (i.e., wet images). This field of view (FOV) was deliberately selected to ensure that our results and subsequent analyses were not affected by capillary end effects. This is in accordance with SCAL best practices as recommended by several researchers (Alizadeh et al. 2014; Kamath et al. 2001; Lin et al. 2019; Wang and Masalmeh 2019). Once a high-quality reference image was obtained, the core was vacuum-saturated with the aqueous phase. The pore pressure was then increased in a stepwise manner while the overburden pressure was adjusted accordingly to maintain a constant net radial confining pressure of 2.07 MPa on the sleeve surrounding the core sample. Several pore volumes of brine were injected to displace trace amounts of CO2 remaining in the pore space at the elevated pore pressure of 5.52 MPa (R.Y. Makhnenko; J.F. Labuz). Afterward, the absolute permeability to brine was measured by injecting water at multiple flow rates and recording the differential pressure data. The temperature of the system was subsequently increased to the target experimental temperature (see Table 3) while the injection of brine was continued at a very low flow rate for an extended period of time to allow for the ionic equilibration between the aqueous ions and the rock minerals.
-
2.
Establishing initial water saturation Each core sample was subjected to a drainage process with the designated oil phase to establish an initial water saturation (Swi) of approximately 0.3. The maximum oil injection flow rates were 0.3 and 12 cm3/min for the micro- and macroscale experiments, respectively. Both selected flow rates corresponded to capillary numbers (Nca) in the order of E−05. The capillary number formula (Eq. 1) used throughout this study is that given by Melrose et al. (Melrose 1974):
$$N_{{{\text{ca}}}} = \frac{{\mu_{i} u_{i} }}{{\emptyset \sigma_{ow} }} = \frac{K\Delta p}{{\emptyset \sigma_{ow} L}}$$(1)where \(\mu_{i}\) and \(u_{i}\) are the viscosity and Darcy velocity of the invading phase, \(\emptyset\) is the porosity of the porous medium, \(\sigma_{ow}\) denotes the interfacial tension between the invading and defending fluids, \(\Delta p\) is the pressure drop, and L is the length of the core.
Once the flow reached a stable (steady-state) condition, the injection was halted to allow the system to equilibrate, and the sample was then imaged at a resolution of 2.7 µm to obtain the fluid occupancy map. The steady-state condition was assumed to be established after the differential pressure along the length of the core and pore fluid configuration after consecutive monitoring scans became stable. The above-mentioned procedure was executed whenever the sample needed to be imaged during the aging and waterflooding stages of the microscale experiments. For the macroscale experiments, fluid production and pressure drop data were used to determine the steady-state conditions. In Experiments G to J, the flow direction was reversed at the end of the drainage processes to establish uniform initial water saturation profiles across the core samples. The drainage tests in Samples A to J led to initial water saturations ranging from 0.31 to 0.34. The presence of a significant amount of microporosity in the samples is believed to be responsible for the relatively high initial water saturations observed in the cores. Similar results in carbonates have been reported by Dernaika and Masalmeh (2019b). This narrow range of initial water saturations and the use of homogenous rock samples and similar fluid properties enabled us to relate the oil recovery trends only to the wettability conditions.
-
3.
Wettability Restoration After establishing Swi, for all experiments except Experiments A, E, and F, the designated polar oil was continuously injected at a very low flow rate (e.g., 1 pore volume per week) and for certain periods of time (see Table 3) to dynamically alter the wettability of the core samples. During the aging process, Samples B and D were scanned intermittently to measure the in situ contact angles and to determine the aging time, i.e., the time required to establish the equilibrium wettability state. This information was subsequently used in the macroscale counterpart experiments to set the aging time. In Experiments E to J, the flow direction was reversed during the dynamic aging process to uniformly alter the wettability over the length of the core samples. For Experiments A to D, however, the samples were relatively shorter in length and it was unnecessary to reverse the flow direction during the aging process. When the aging processes were concluded, the resident crude oil mixtures were miscibly displaced with 5 to 10 pore volumes (PVs) of decalin followed by 10–20 PVs of Soltrol 170. The sample was imaged once more to generate the distributions of contact angles prior to waterflooding. The comparison between the contact angle distributions before and after injecting decalin and Soltrol 170 confirmed that the contact angle distribution was preserved after conducting the aforementioned experimental stages.
-
4.
Water looding When the core samples were aged and the crude oil mixtures were displaced by Soltrol 170, the temperature of the system was adjusted to 50 °C and the core samples were waterflooded with 20 PV of the synthetic brine at low flow rates, i.e., under a capillary-dominated flow regime. The brine was injected from the bottom face of the core while the effluent was produced from the top side. The waterfloods were conducted in stages while the number of pore volume of water injected (PVWI) was increased. The pressure drop and production data were constantly monitored during the injection process. The injection flow rates were then increased in steps (as listed in Table 4) to investigate the effect of flow rate on the remaining oil saturation in the macroscale tests. The multi-rate waterflooding experiments allowed us to overcome the capillary end effects that exist particularly in non-water-wet samples. During each step, a number of pore volumes was injected until the saturation and pressure drop along the length of the core became stable.
During the waterflooding tests, either the sample was scanned to generate fluid occupancy maps (in the microscale tests) or the effluent samples were analyzed (in the macroscale experiments) to measure residual/remaining oil saturation (i.e., Sor) values. The oil production data was converted to oil recovery factors using Equation 2 to compensate for minor differences in the initial water saturations.
Lastly, it should be noted that reservoir formation brines may be significantly different than the aqueous phase used in this study in terms of composition, ionic strength, pH, and divalent/monovalent cation ratio, which impact the equilibrium wettability state of the rock. Nonetheless, in each case, the pore-scale flow mechanisms and recovery trend would be similar to the respective system in our study.
Rights and permissions
About this article
Cite this article
Ekechukwu, G.K., Khishvand, M., Kuang, W. et al. The Effect of Wettability on Waterflood Oil Recovery in Carbonate Rock Samples: A Systematic Multi-scale Experimental Investigation. Transp Porous Med 138, 369–400 (2021). https://doi.org/10.1007/s11242-021-01612-3
Received:
Accepted:
Published:
Issue Date:
DOI: https://doi.org/10.1007/s11242-021-01612-3