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Waterflooding in carbonate reservoirs
Waterflooding involves the use of injected water to displace oil in a reseroir. This process is a method of secondary recovery. Conventional oil recovery involves improving volumetric sweep efficiency via a variety of technologies and practices, including in-fill drilling, multilateral wells, improved reservoir characterization, high resolution reservoir simulation, and advanced monitoring and surveillance. Around 50% of the world’s known oil resolves are in carbonate reservoirs. As Primary recovery mechanisms yield low recovery factors and therefore companies seek Secondary or even Tertiary recovery methods.
When Waterflooding a carbonate reservoir, one must consider the same issues that affect any type of recovery, which can determine the success of oil recovery. The factors that cannot be changed, the properties of the formation itself, must be worked around and the water used in flooding modified. Those factors include:
- Matrix permeability
- Fracture Intensity
- Rock properties
- Fluid properties
- Contact angle
In waterflooding, the water displaces oil from the pore spaces, but the efficiency of such displacement depends on many factors, including oil viscosity and rock characteristics. Because carbonate surfaces are positively charged, the water must be altered, generally by adjusting the salinity, which will affect the concentration of sulfate ions (SO42‐), calcium ions (Ca2+), or magnesium ions (Mg2+).
Studies have found that lowering the salinity of the injection water to different degrees can change rock wettability and improve oil recovery. But it still is not clear why lower salinity water causes this effect. According to Gupta, et al., three main theories exist:
- Rock dissolution: First proposed by Hiorth et al., this theory explains the low-salinity effect by hypothesizing that the lower calcium concentration in low-salinity brine causes calcium carbonate from the rock to dissolve and establish equilibrium with the brine. When the calcium carbonate dissolves, the adsorbed oil components are removed and the rock surface is rendered more water-wet.
- Surface ion exchange: At typical carbonate reservoir conditions, rock surfaces have a positive charge while the acidic components of oil have a negative charge, causing the rock to be oil-wet or mixed-wet. If the determining anions in the water (e.g. SO42-) have a higher affinity to the rock surface than the acidic oil components, the anions are adsorbed and the oil is desorbed. If the rock surface charge is decreased (e.g. because of low salinity), desorption of negatively charged oily material is also facilitated.
- In-situ surfactant formation: The potential of in-situ surfactant generation requires a high pH and Hiorth et al. determined it to be a rare mechanism in waterflooding.
Waterflooding is the most successful method for recovering oil from reservoirs, mainly because: a) as an injectant, water is efficient in displacing oil of light to medium gravity; b) water is fairly easy to inject into oil-bearing formations; c) water is cheap and readily available; d) waterflooding requires lower capital investment and operating cost, which makes it more economical than EOR methods.
Because about 80% of these geologic formations are oil-wet, carbonate reservoirs pose a problem in oil recovery. The negatively–charged carboxylic acid anions in oil are attracted to positively-charged carbonate surfaces, thus generating oil-wet surfaces. Waterflooding can be ineffective in recovery from carbonate reservoirs because the capillary pressure curve is predominantly negative, therefore surfactant/polymer waterflooding is considered by some in the industry to be a more viable option. 
- Gupta, R., Smith, G., Hu, L., et al. 2011. Enhanced Waterflood for Carbonate Reservoirs - Impact of Injection Water Composition. Presented at the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25-28 September. SPE-142668-MS. http://dx.doi.org/10.2118/142668-MS.
- Yousef, A., Al-Saleh, S., Al-Jawfi, M.S. The Impact of the Injection Water Chemistry on Oil Recovery from Carbonate Reservoirs. Presented at the SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 16-18 April. SPE-141082-MS. http://dx.doi.org/10.2118/154077-MS.
- Seethepalli, A., Adibhatla, B., and Mohanty, K.K. 2004. Wettability Alteration During Surfactant Flooding of Carbonate Reservoirs. Presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 17-21 April. SPE-89423-MS. http://dx.doi.org/10.2118/89423-MS.
- Thyne, G., Romero, M., and Gamage, P. 2011. Adjusted Brine Chemistry (Designer Waterfloods). Presentation, Enhanced Oil Recovery Institute, University of Wyoming. http://www.uwyo.edu/eori/_files/eortab_jan11/geoff_eori%20tab%20designer%20wf_1_18_11_fin.pdf.
Noteworthy papers in OnePetro
Alotaibi, M.B., Nasralla, R.A., and Nasr-El-Din, H.A. 2011a. Wettability Studies Using Low-Salinity Water in Sandstone Reservoirs. SPE Res Eval & Eng 14 (6): 713–725. SPE-149942-PA. http://dx.doi.org/10.2118/149942-PA.
Alotaibi, M.B., Nasr-El-Din, H.A., and Fletcher, J.J. 2011b. Electrokinetics of Limestone and Dolomite Rock Particles. SPE Res Eval & Eng 14 (5): 594–603. SPE-148701-PA. http://dx.doi.org/10.2118/148701-PA.
Alotaibi, M.B. and Nasr-El-Din, H.A. 2011. Electrokinetics of Limestone Particles and Crude-Oil Droplets in Saline Solutions. SPE Res Eval & Eng 14 (5): 604–611. SPE-151577-PA. http://dx.doi.org/10.2118/151577-PA.
Chandrasekhar, S. and Mohanty, K.K. 2013. Wettability Alteration With Brine Composition in High Temperature Carbonate Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 September–2 October. SPE-166280-MS. http://dx.doi.org/10.2118/166280-MS.
Farida, A., Hashem, S.H., Abdulraheem B. et al. 2013. First EOR Trial Using Low Salinity Water Injection in the Greater Burgan Field, Kuwait. Presented at the 18th Middle East Oil and Gas Show and Conference, Manama, Bahrain, 10–13 March. SPE-16434-MS. http://dx.doi.org/10.2118/16434-MS.
Fathi, S.J., Austad, T., and Strand, S. 2012. Water-Based Enhanced Oil Recovery (EOR) by “Smart Water” in Carbonate Reservoirs. Presented at the EOR Conference at Oil and Gas West Asia, Muscat, Oman, 16–18 April. SPE-154570-MS. http://dx.doi.org/10.2118/154570-MS.
Hall, A.C., Collins, S.H., and Melrose, J.C. 1983. Stability of Aqueous Wetting Films in Athabasca Tar Sands. SPE J. 23 (2): 249–258. SPE-10626-PA. http://dx.doi.org/10.2118/10626-PA.
Hognesen, E.J., Strand, S., and Austad, T. 2005. Waterflooding of Preferential Oil-Wet Carbonates: Oil Recovery Related to Reservoir Temperature and Brine Composition. Presented at the SPE Europec/EAGE Annual Conference, Madrid, Spain, 13–16 June. SPE 94166-MS. http://dx.doi.org/10.2118/94166-MS.
Kaminsky, R. and Radke, C.J. 1997. Asphaltenes, Water Films, and Wettability Reversal. SPE J. 2 (4): 485–493. SPE-39087-PA. http://dx.doi.org/10.2118/39087-PA.
Kussakov, M.M. and Mekenitskaya, L.I. 1955. 5. On the Thickness of Thin Layers of Connate Water. Presented at the 4th World Petroleum Congress, Rome, Italy, 6–15 June. SPE-6134-MS. http://dx.doi.org/10.2118/6134-MS.
McGuire, P.L., Chatham, J.R., Paskvan, F.K. et al. 2005. Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska’s North Slope. Presented at the SPE Western Regional Meeting, Irvine, California, 30 March–1 April. SPE-93903-MS. http://dx.doi.org/10.2118/93903-MS.
Morrow, N. and Buckley, J. 2011. Improved Oil Recovery by Low-salinity Waterflooding. J Pet Technol 63 (5): 106–112. SPE-129421-PA. http://dx.doi.org/10.2118/129421-PA.
Nasralla, R.A. and Nasr-El-Din, H.A. 2011. Impact of Electrical Surface Charges and Cation Exchange on Oil Recovery by Low Salinity Water. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, 20–22 September. SPE-147937-MS. http://dx.doi.org/10.2118/147937-MS.
Nasralla, R.A. and Nasr-El-Din, H.A. 2014. Double-Layer Expansion: Is It a Primary Mechanism of Improved Oil Recovery by Low-Salinity Waterflooding? SPE Res Eval & Eng 17 (1): 49–59. SPE-154334-PA. http://dx.doi.org/10.2118/154334-PA.
Seccombe, J.C., Lager, A., Webb, K. et al. 2008. Improving Waterflood Recovery: LoSal EOR Field Evaluation. Presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma, 20–23 April. SPE-113480-MS. http://dx.doi.org/10.2118/113480-MS.
Yousef, A.A., Al-Saleh, S.H., and Al-Kaabi, A. 2011. Laboratory Investigation of the Impact of Injection-Water Salinity and Ionic Content on Oil Recovery From Carbonate Reservoirs. SPE Res Eval & Eng 14 (5): 578–593. SPE-137634-PA. http://dx.doi.org/10.2118/137634-PA.
Zahid, A., Stenby, E.H., and Shapiro, A.A. 2012. Smart Waterflooding (High Sal/Low Sal) in Carbonate Reservoirs. Presented at the SPE Europec/EAGE Annual Conference, Copenhagen, Denmark, 4–7 June. SPE-154508-MS. http://dx.doi.org/10.2118/154508-MS.
Other noteworthy papers
Ajwa, H.A. and Tabatabai, M.A. 1995. Metal-induced Sulfate Adsorption by Soils: Effect of pH and Ionic Strength. Soil Sci. 159 (1): 32–42. http://dx.doi.org/10.1097/00010694-199501000-00004.
Aksulu, H. 2010. Effect of Core Cleaning Solvents on Wettability Restoration and Oil Recovery by Spontaneous Imbibition in Surface Reactive, Low Permeable Limestone Reservoir Cores. MSc thesis, University of Stavanger, Stavanger, Norway (October 2010).
Austad, T., Shariatpanahi, S.F., Strand, S. et al. 2011. Conditions for a Low-Salinity Enhanced Oil Recovery (EOR) Effect in Carbonate Oil Reservoirs. Energy Fuels 26 (1): 569–575. http://dx.doi.org/10.1021/ef201435g.
W. Yun, C. M. Ross, S. Roman, and A. R. Kovscek. Creation of a dual-porosity and dual-depth micromodel for the study of multiphase flow in complex porous media. Lab on a Chip, 17(8):1462–1474, 2017.https://doi.org/10.1039/C6LC01343K.
Barrow, N.J. and Shaw, T.C. 1977. The Slow Reactions between Soil and Anions: 7. Effect of Time and Temperature of Contact Between an Adsorbed Soil and Sulfate. Soil Sci. 124 (6): 347–354. http://dx.doi.org/10.1097/00010694-197712000-00007.
Buckley, J.S. and Liu, Y. 1998. Some Mechanisms of Crude Oil/Brine/Solid Interactions. J. Petrol. Sci. & Eng. 20 (3–4): 155–160. http://dx.doi.org/10.1016/S0920-4105(98)00015-1.
Chilingar, G.V. and Yen, T.F. 1993. Some Notes on Wettability and Relative Permeabilities of Carbonate Reservoir Rocks, II. Energy Sources 7 (1): 67–75. http://dx.doi.org/10.1080/00908318308908076.
Farooq, O., Tweheyo, M.T., Sjöblom, J. et al. 2011. Surface Characterization of Model, Outcrop, and Reservoir Samples in Low Salinity Aqueous Solutions. J. Dispersion Sci. & Technol. 32 (4): 519–531. http://dx.doi.org/10.1080/01932691003756936.
Fathi, S.J., Austad, T., and Strand, S. 2010. “Smart Water” as a Wettability Modifier in Chalk: The Effect of Salinity and Ionic Composition. Energy Fuels 24 (4): 2514–2519. http://dx.doi.org/10.1021/ef901304m.
Fathi, S.J., Austad, T., and Strand, S. 2011. Water-Based Enhanced Oil Recovery (EOR) by “Smart Water”: Optimal Ionic Composition for EOR in Carbonates. Energy Fuels 25 (11): 5173–5179. http://dx.doi.org/10.1021/ef201019k.
Hiorth, A., Cathles, L.M., and Madland, M.V. 2010. The Impact of Pore Water Chemistry on Carbonate Surface Charge and Oil Wettability. Transport in Porous Media 85 (1): 1–21. http://dx.doi.org/10.1007/s11242-010-9543-6.
Knecht, V., Risselada, H.J., Mark, A.E. et al. 2007. Electrophoretic Mobility Does Not Always Reflect the Charge on an Oil Droplet. J. Colloid Interface Sci. 318 (2): 477–486. http://dx.doi.org/10.1016/j.jcis.2007.10.035.
Omotoso, O.E., Munoz, V.A., and Mikula, R.J. 2002. Mechanisms of Crude Oil-Mineral Interactions. Spill Sci. & Technol. Bull. 8 (1): 45–54. http://dx.doi.org/10.1016/S1353-2561(02)00116-0.
Puntervold, T., Strand, S., and Austad, T. 2007. New Method to Prepare Outcrop Chalk Cores for Wettability and Oil Recovery Studies at Low Initial Water Saturation. Energy Fuels 21 (6): 3425–3430. http://dx.doi.org/10.1021/ef700323c.
Shariatpanahi, S.F., Strand, S., and Austad, T. 2011. Initial Wetting Properties of Carbonate Oil Reservoirs: Effect of the Temperature and Presence of Sulfate in Formation Water. Energy Fuels 25 (7): 3021–3028. http://dx.doi.org/10.1021/ef200033h.
Smallwood, P.V. 1977. Some Aspects of the Surface Chemistry of Calcite and Aragonite, Part I: An Electrokinetic Study. Colloid & Polymer Sci. 255: 881–886. http://dx.doi.org/10.1007/bf01617095.
Standnes, D.C. and Austad, T. 2000. Wettability alteration in chalk: 1. Preparation of core material and oil properties. J. Pet. Sci. Eng. 28 (3): 111-121. http://dx.doi.org/10.1016/S0920-4105(00)00083-8.
Tang, G. and Morrow, N.R. 1999. Influence of Brine Composition and Fines Migration on Crude Oil/Brine/Rock Interactions and Oil Recovery. J. Pet. Sci. Eng. 24 (2–4): 99–111. http://dx.doi.org/10.1016/S0920-4105(99)00034-0.
Zhang, P., Tweheyo, M.T., and Austad, T. 2007. Wettability Alteration and Improved Oil Recovery by Spontaneous Imbibition of Seawater Into Chalk: Impact of the Potential Determining Ions Ca2+, Mg2+, and SO42-. Colloids and Surfaces A: Physicochem. & Eng. Aspects 301 (1–3): 199–208. http://dx.doi.org/10.1016/j.colsurfa.2006.12.058.
Brown, W.O. 1957. The Mobility of Connate Water During a Water Flood. In Transactions of the American Institute of Mining Engineers, Vol. 210, SPE-694-G, 190–195. New York: AIME.
Green, D.W. and Willhite, G.P. 1998. Enhanced Oil Recovery, Chap. 2, 12–34. Richardson, Texas: SPE.
Masden, L. 2006. Calcite: Surface Charge. In Encyclopedia of Surface and Colloid Science, ed. P. Somasundaran, Vol. 2, 1084-1096. Boca Raton, Florida: CRC Press.
Russel, R.G., Morgan, F., and Muskat, M. 1947. Some Experiments on the Mobility of Interstitial Waters. In Transactions of the American Institute of Mining and Metallurgical Engineers, Vol. 170, 51–61. New York: AIME.
Schumacher, M.M. 1978. Enhanced Oil Recovery: Secondary and Tertiary Methods, Chap. 2, 23. Park Ridge, New Jersey: Noyes Data Corp.
Willhite, G.P. 1986. Waterflooding, Chap. 7, 257-269. Richardson, Texas: SPE.
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