Energy Fuels 2010, 24, 3950–3958 Published on Web 06/25/2010
: DOI:10.1021/ef1001716
Dynamic Laboratory Wettability Alteration M. A. Fernø,* M. Torsvik, S. Haugland, and A. Graue Department of Physics and Technology, University of Bergen, All egaten 55, 5007 Bergen, Norway Received February 11, 2010. Revised Manuscript Received June 1, 2010
We present experimental wettability alteration results in originally strongly water-wet, outcrop chalk core plugs using a static and two dynamic aging methods. Dynamic aging with continuous crude oil injection during the entire aging process exhibited greater reduction in water-wetness of the strongly water-wet chalk plugs than static aging without flushing. Two dynamic aging procedures were tested to find an optimal flooding rate for the most efficient reduction in water-wetness: (1) a constant crude oil flooding at 3 cm3/h using variable aging times (48, 96, and 192 h) and (2) a constant aging time (96 h) with variable flooding rates (1, 3, and 5 cm3/h). The aging temperature was kept constant in all tests (90 °C), and the impacts from varying aging times, pore volumes injected, and crude oil injection rate on the wettability alteration process were investigated. Aging was performed on consolidated, porous chalk samples with initial water present in the pore space. It was shown that static aging, i.e., aging in a stagnant, limited amount of crude oil, and dynamic aging, i.e., with continuous flooding of crude oil, performed equally well in terms of average Amott-Harvey water indices (Iw ∼0.6) for short aging times (72 h or less). For longer aging times, the static approach failed to established an Amott-Harvey water index under Iw =0.25 and required 3 times as long of an aging time compared to dynamic aging (7 days for dynamic or 24 days for static required to establish Iw ∼ 0.25). Amott-Harvey water indices lower than Iw = 0.25 were established with dynamic aging for shorter aging times (less than 12 days). At a given constant aging time (96 h), it was found that wetting was sensitive to the crude oil injection rate and that there exists an optimal crude oil injection rate with the greatest change in wettability.
The wettability of the reservoir rock determines the microscopic fluid distribution in the pore space and impacts the relative flow of water and oil, capillary pressure, relative permeability, oil recovery, electrical properties, and nuclear magnetic resonance (NMR) relaxation behavior.1-6 The wettability is therefore one of the most important parameters in core analysis when reservoir-specific flow conditions are evaluated.7 The wettability of reservoir core plugs changes during coring and transport from the sub-surface and should be restored in the laboratory to be representative of the reservoir. Similarly, outcrop rocks, which usually are strongly water-wet, need to be prepared by a wettability alteration procedure to be used as reservoir analogues. Thus, in both cases, the wettability must be altered, which is normally achieved by contacting the rock surface with crude oil at elevated temperatures for a longer period of time (typically 1000 h1). However, a generally accepted best procedure to alter the wettability in core plugs using crude oil has not been reported, and several of the existing methods are associated with experimental artifacts, such as
non-uniform wettability distributions, inefficiency, and poor or uncertain reproducibility.8-10 The composition of crude oil greatly impacts the wettability change of naturally water-wet rock surfaces during aging because of differences in the aging ability for the components present in crude oil. The presence of surface-active polar components in the crude oil that could change the wettability was first identified by Benner and Bartell.11 Bulk-oil composition determines the solubility of the polar components, and a crude oil that is a poor solvent for its own surfactants will have a greater propensity to change wettability than one that is a good solvent.12 The exact nature of the adsorbed polar components in the crude oil is still unknown13 but is believed to be governed by more than one mechanism. The main mechanisms of wettability alteration in porous media by crude oil include the polar interaction between oil components and solid, surface precipitation, acid/base interactions controlling the surface charge at interfaces, and ion binding between charged sites14 and higher valency ions.15 The oil must displace the water film that covers the surface to alter the wettability of water-wet rock surfaces. The polar
*To whom correspondence should be addressed. Telephone: þ47-5558-27-92. Fax: þ47-55-58-94-40. E-mail:
[email protected]. (1) Anderson, W. J. Pet. Technol. 1986, 38 (11), 1246–1262. (2) Anderson, W. G. J. Pet. Technol. 1986, 38 (12), 1371–1378. (3) Anderson, W. G. J. Pet. Technol. 1986, 38 (10), 1125–1144. (4) Anderson, W. G. J. Pet. Technol. 1987, 39 (12), 1605–1622. (5) Anderson, W. G. J. Pet. Technol. 1987, 39 (11), 1453–1468. (6) Anderson, W. G. J. Pet. Technol. 1987, 39 (10), 1283–1300. (7) Abdallah, W.; Buckley, J. S.; Carnegie, A.; Edwards, J.; Herold, B.; Fordham, E.; Graue, A.; Habashy, T.; Seleznev, N.; Signer, C.; Hussain, H.; Montaron, B.; Ziauddin, M. The fundamentals of wettability. Oilfield Review 2007, 19 (2), 44–63.
(8) Graue, A.; Viksund, B. G.; Baldwin, B. A. SPE Reservoir Eval. Eng. 1999, 2 (2), 134–140. (9) Graue, A.; Aspenes, E.; Bogno, T.; Moe, R. W.; Ramsdal, J. J. Pet. Sci. Eng. 2002, 33 (1-3), 3–17. (10) Spinler, E. A.; Baldwin, B. A.; Graue, A. J. Pet. Sci. Eng. 2002, 33 (1-3), 49–59. (11) Benner, F. C.; Bartell, F. E. Drill. Prod. Pract. 1942, 341–348. (12) Al-Maamari, R. S. H.; Buckley, J. S. SPE Reservoir Eval. Eng. 2003, 6 (4), 210–214. (13) Kumar, K.; Dao, E.; Mohanty, K. K. J. Colloid Interface Sci. 2005, 289 (1), 206–217. (14) Hirasaki, G. J. SPE Form. Eval. 1991, 6 (2), 217–226. (15) Buckley, J. S.; Liu, Y.; Monsterleet, S. SPE J. 1998, 3 (1), 54–61.
Introduction
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components of the crude oil collect at the water/oil interface and may adsorb onto the mineral surface if the water film breaks. The stability of the water film is determined by the disjoining pressure and depends upon factors such as water chemistry, physical and chemical properties of solid surfaces, and oil composition.16 Understanding the whole nature and the extent of interactions between pore wall and surface-active components in the crude oil is difficult because all three phases in the crude oil/brine/rock system are mixtures of many components themselves.17 Other parameters that have been found to influence wettability alteration include the mineral composition and surface charge of the rock,3,18,19 brine composition and salinity and concentration of divalent and other multivalent ions,20,21 capillary pressure and thin film forces,14,22 water solubility of polar components,3,23 solvent power of oil for its heavy components,19,24 and temperature, pressure, initial water, and volume throughputs.24-28 This work compares the aging and wettability alteration established by a static and two dynamic aging procedures using crude-oil-induced wettability change in outcrop chalk. Static aging relates to cores stored in a core holder or beaker containing crude oil at elevated temperatures. During dynamic aging, crude oil was continuously injected through the core at elevated temperatures. Two dynamic aging procedures were adopted: (1) a constant crude oil injection rate of 3 cm3/h using variable aging times (48, 96, and 192 h) and (2) a constant aging time (96 h) with variable injection rates (1, 3, and 5 cm3/h). The aging temperature was kept constant in all tests (90 °C), and the impacts from varying aging times, pore volumes injected, and crude oil injection rate on the wettability alteration process were investigated. Additionally, the storage time and level of crude oil evaporation and oxidation (E&O) at 90 °C were varied to assess its impact on changing the wettability preference. Crude oil from the same barrel was used for all tests. All aging was performed on consolidated, porous chalk samples with initial water present in the pore space. The change in wettability during aging was evaluated by the reduction in water imbibition rates, amount of
spontaneously imbibed water, and the Amott-Harvey water index.29 This particular chalk/crude oil combination does not spontaneously displace water by capillary attraction of oil, even after aging.9,27 The Amott-Harvey oil index was therefore not measured. The objectives were, first, to compare dynamic aging to static aging with similar aging times, second, to investigate if the level of crude oil E&O influenced the ability of the crude oil to alter the wettability, and third, to determine if there exists an optimal injection rate with the greatest change in wettability during dynamic wettability alteration. Experimental Section Rock Material. The chalk core plugs were cut from larger blocks of rock obtained from the Portland cement factory in Rørdal near A˚lborg, Denmark. The core material were turned on the lathe after drying to obtain cylindrical core plugs, rather than using standard core-drilling equipment, to avoid microfractures. The rock formation was of Maastrichtian age and consisted mainly of coccolith deposits. The composition was calcite (99%) with some quartz (1%). The brine permeability and porosity ranged from 1 to 4 mD and 45-48%, respectively. Air permeability was not measured. More details may be found elsewhere.30,31 The core plugs were dried at 90 °C for at least 3 days. Dry weight and core plug dimensions were measured before the core plugs were vacuum-evacuated and saturated with brine. Porosity was determined by material balance calculations. Absolute permeability to brine was determined by measuring the pressure drop across the rock sample at different flow rates in a biaxial core holder with a slight confinement pressure. Flow rates used ranged from 10 to 100 cm3/h, and the net confinement pressure did not exceed 10 bar. Measured core data are listed in Table 1. Table 1 lists the core properties, established Amott-Harvey water indices, crude oil injection rates used during dynamic aging, aging time, number of days used to evaporate and oxidize the crude oil at 90 °C, and condition of the chalk filter used to filter the crude oil. Fluids. The composition of the brine was 5 wt % NaCl and 3.8 wt % CaCl2. Sodium azide (0.01 wt %) was added to prevent bacterial growth. The density and viscosity of the brine was 1.05 g/cm3 and 1.09 cP at 20 °C. Properties of the mineral oil and crude oil are listed in Table 2a. A summary of crude oil chemical analysis including saturate, aromatic, resin, and asphaltene (SARA) components, API, refractive index, and acid and base numbers is tabulated in Table 2b. This analysis represents crude oil without E&O at 90 °C. Crude Oil Preparation and Filtration. Crude oil from the same barrel was used to age all cores in this study. Crude oil batches for aging were extracted from the barrel within a time period of 3-4 months. For each batch, the barrel was rotated to mix the crude oil before collecting oil. The crude oil in the barrel was not stored under a blanket of inert gas and, therefore, was exposed to air during storage. The barrel was closed between collecting each batch. The crude oil was transferred to an accumulator, heated to 90 °C, and injected through a chalk core at a constant injection rate to remove impurities. Before use, the chalk core filter was flooded with crude oil to low water saturation and aged by flushing crude oil through the core at 1 cm3/h for 96 h, reversing the flow direction midway. The crude oil used for aging the filter core plug was not reused in the wettability alteration study. Because of its aged state, it was assumed that the adsorption of active wettability alteration components in the filter was significantly reduced. During filtration, preheated crude oil was injected from one accumulator through the filter and collected in a
(16) Basu, S.; Sharma, M. M. Defining the wettability state of mixed wet reservoirs: Measurement of critical capillary pressure for crude oils. Proceedings of the Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition (ATCE); Denver, CO, 1996. (17) Salehi, M. Ph.D. Dissertation, Kansas University, Lawrence, KS, 2009. (18) Dubey, S. T.; Waxman, M. H. SPE Reservoir Eval. Eng. 1991, 6 (3), 389–395. (19) Buckley, J. S.; Hirasaki, G. J.; Liu, Y.; Von Drasek, S.; Wang, J.-X.; Gill, B. S. Pet. Sci. Technol. 1998, 16 (3-4), 251–285. (20) Buckley, J. S.; Takamura, K.; Morrow, N. R. SPE Reservoir Eng. 1989, 4 (3), 332–340. (21) Xie, X.; Morrow, N. R. J. Adhes. Sci. Technol. 2000, 13 (10), 1119–1135. (22) Melrose, J. C. Interpretation of mixed wettability states in reservoir rocks. Proceedings of the Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition (ATCE); New Orleans, LA, 1982. (23) Kaminsky, R.; Radke, C. J. SPE J. 1997, 2 (4), 485–493. (24) Al-Maamari, R. S. H.; Buckley, J. S. Asphaltene precipitation and alteration of wetting: Can wettability change during oil production? Proceedings of the Society of Petroleum Engineers (SPE)/ Department of Energy (DOE) Improved Oil Recovery Symposium; Tulsa, OK, 2000. (25) Jia, D.; Buckley, J. S.; Morrow, N. R. Control of core wettability with crude oil Proceedings of the Society of Petroleum Engineers (SPE) International Symposium on Oilfield Chemistry; Anaheim, CA, 1991. (26) Jadhunandan, P. P.; Morrow, N. R. SPE Reservoir Eng. 1995, 10 (1), 40–46. (27) Graue, A.; Viksund, B. G.; Eilertsen, T.; Moe, R. J. Pet. Sci. Eng. 1999, 24 (2-4), 85–97. (28) Aspenes, E.; Graue, A.; Ramsdal, J. J. Pet. Sci. Eng. 2003, 39 (3-4), 337–350.
(29) Amott, E. Trans. AIME 1959, 216, 156–162. (30) Ekdale, A. A.; Bromley, R. G. Bull. Geol. Soc. Den. 1993, 31, 107–119. (31) Hjuler, M. L. Ph.D. Dissertation, Technical University of Denmark, Copenhagen, Denmark, 2007.
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Table 1. Core Properties, Intermediate Water Saturations, Amott-Harvey Water Index, and Aging Time
core C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32 C33 C34
length diameter porosity (cm) (cm) (fraction) 7.53 7.54 7.56 7.55 7.60 8.07 7.59 7.95 7.84 7.66 7.74 8.05 8.03 8.01 8.02 8.04 7.74 8.02 8.04 8.01 8.02 8.03 8.01 8.02 8.00 8.00 8.01 7.52 8.02 7.91 8.04 8.00 8.00 8.01
5.09 5.09 5.09 5.09 5.08 5.07 5.09 5.08 5.09 5.13 5.10 5.09 5.06 5.08 5.07 5.07 5.09 5.08 5.07 5.08 5.11 5.07 5.10 5.09 5.09 5.07 5.08 5.09 5.07 5.09 5.08 5.08 5.05 5.07
0.47 0.46 0.46 0.47 0.46 0.48 0.46 0.47 0.48 0.47 0.47 0.47 0.47 0.46 0.47 0.47 0.46 0.47 0.47 0.46 0.46 0.47 0.47 0.47 0.48 0.46 0.46 0.46 0.47 0.46 0.45 0.47 0.47 0.46
Amottbrine Sw_spont Rf Sw_wf Harvey Swi permeability (fraction (fraction (fraction (fraction water of PV) of PV) of PV) of PV) index, Iw (mD) 3.47 3.10 3.45 4.10 3.88 2.96 4.30 3.02 4.02 3.00 6.43 3.88 4.17 3.61 5.00 4.92 4.42 4.75 4.05 3.61 4.43 4.00 4.40 4.00 3.82 4.40 5.40 5.10 5.40 3.90 3.50 6.80 3.30 5.40
0.26 0.26 0.25 0.25 0.26 0.25 0.25 0.26 0.24 0.26 0.24 0.26 0.26 0.25 0.25 0.26 0.25 0.25 0.25 0.26 0.25 0.25 0.25 0.26 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25
0.65 0.65 0.63 0.66 0.65 0.60 0.59 0.61 0.53 0.49 0.59 0.33 0.32 0.38 0.31 0.35 0.36 0.29 0.28 0.32 0.55 0.51 0.48 0.33 0.41 0.49 0.35 0.47 0.36 0.30 0.46 0.42 0.43 0.38
0.53 0.53 0.51 0.55 0.52 0.46 0.46 0.47 0.38 0.32 0.46 0.09 0.08 0.17 0.08 0.12 0.15 0.05 0.04 0.08 0.41 0.35 0.31 0.09 0.21 0.32 0.13 0.30 0.15 0.06 0.28 0.22 0.24 0.17
0.65 0.65 0.63 0.66 0.65 0.73 0.73 0.71 0.75 0.71 0.72 0.70 0.64 0.81 0.70 0.65 0.73 0.72 0.71 0.80 0.79 0.65 0.72 0.55 0.67 0.65 0.86 0.74 0.69 0.68 0.67 0.60 0.69 0.71
injection rate (mL/h)
aging time (h)
E&O (days)
filter (condition)
0 0 0 0 0 0 0 0 0 3 3 3 3 3 3 3 3 3 3 3 3 3 3 1 1 1 3 3 3 5 5 5
336 336 336 72 72 72 72 72 72 48 48 48 96 96 96 192 192 192 48 48 96 96 96 96 96 96 96 96 96 96 96 96
0 0 0 0 0 0 >3 >3 3 >3 3 3 >3 >3 >3 0 0 0 0 0 2 >15 2 9 >15 2 2 3 >15
SWW SWW SWW aged aged SWW aged aged aged aged aged aged aged aged aged aged aged aged SWW aged aged aged aged aged aged aged aged aged aged
1.00 1.00 1.00 1.00 1.00 0.72 0.72 0.77 0.57 0.52 0.73 0.16 0.16 0.23 0.13 0.23 0.23 0.08 0.06 0.10 0.56 0.66 0.49 0.24 0.38 0.60 0.16 0.46 0.25 0.11 0.49 0.47 0.40 0.28
Table 2 (a) Mineral and Crude Oil Properties
paraffin lamp oil decane decahydronaphthalene crude oil
density at 20 °C (g/cm3)
density at 90 °C (g/cm3)
viscosity at 20 °C (cP)
viscosity at 90 °C (cP)
0.75 0.73 0.89 0.85
0.69 0.68
1.4 0.92 0.85 14.3
0.48 0.40
0.85
2.7
(b) Crude Oil Composition AN (mg of KOH/g of oil)
BN (mg of KOH/g of oil)
RI
API (deg)
saturates (%)
aromatics (%)
resins (%)
asphaltenes (%)
0.41 ( 0.02
1.4 ( 0.1
1.4834
27 ( 3
61 ( 3
20 ( 1
19 ( 1
0.59 ( 0.03
second accumulator, all at 90 °C (see Figure 1). No water was mobilized during crude oil filtration. After filtration, the crude oil was stored in closed containers at 90 °C with minimal interference and without air exposure until used to age the cores. Some batches were stored in open containers for controlled air exposure at elevated temperatures (90 °C) to promote E&O. Static Aging Procedure. Fully water-saturated chalk cores were placed in a biaxial core holder with a slight net confinement pressure (3 days). Increased aging time leads to increased aging within each oxidation level. Note the different scales on the y axes.
dynamic aging, with reduced wetting preference for increased aging time. The change in wettability varied greatly for each aging time but correlated to the level of crude oil E&O, i.e., the number of days that the crude oil had been oxidized at 90 °C. Results are divided into three graphs above. No Oxidation. Five cores were aged using crude oil without oxidation, using two different aging times (see top left panel in Figure 3). Cores 21 and 22 were dynamically aged for 48 h and exhibited water indices of Iw = 0.56 and 0.66, respectively. Core C23 was dynamically aged for 96 h and obtained a lower wetting of Iw = 0.49. Core C24 (not shown) was aged for 96 h with an Iw = 0.24, significantly lower than the twin plug C23. The produced oil from C24 was discolored because of confinement oil leakage and will not be further discussed. Core C25 (not shown) was aged for 96 h with a water index of Iw = 0.38. 3 Days of Oxidation. Three cores were aged using two different aging times with a crude oil oxidized for 3 days (see top right panel in Figure 3). Core C14 obtained a water index of Iw = 0.23 after 48 h of dynamic aging. Core 16 and C17 established a wetting of Iw =0.23 for both cores after 98 h of dynamic aging. More than 3 Days of Oxidation. Six cores were aged using three different aging times with a crude oil with more than 3 days of oxidation (see bottom panel in Figure 3). After 48 h of dynamic aging, cores C12 and C13 both exhibited AmottHarvey water indices of Iw = 0.16. After 96 h of dynamic aging, core C15 obtained Iw = 0.13, and after 192 h of dynamic aging, cores C18, C19, and C20 established wettability water indices of Iw = 0.08, 0.06, and 0.10, respectively.
Dynamic Aging at a Constant Aging Time with Different Injection Rates. Spontaneous imbibition curves for cores using a constant aging time (96 h) and variable injection rates (1, 3, and 5 cm3/h) are summarized in Figure 4. Water saturations, spontaneous imbibition recoveries, and water indices are summarized in Table 1. Flood Rate Sensitivity. Nine cores (C26-C34) were aged for 96 h with different crude oil injection rates to study the flow rate sensitivity on the dynamic wettability alteration process. The results show that the crude oil flood rate applied during dynamic aging influences the degree of wettability change when the aging time remains the same. The lowest rate (1 cm3/h) provided the least change in wetting, with an average wetting of Iw = 0.53 after 96 h (cores C26 and C28). Increasing the crude oil injection rate to 3 cm3/h reduced the Amott-Harvey water index to an average Iw = 0.31 (cores C16, C17, and C31). A further increase in the crude oil injection rate to 5 cm3/h increased the average Amott-Harvey water index to Iw =0.44 (C32 and C33). Crude oil E&O levels were 2 or 3 days for the cores used to calculate average values within each injection rate group. The obtained wetting preference within each flood rate was influenced by the properties of the crude oil and correlated to the level of oxidation. Results from each crude oil injection rate group are compared for similar oxidation levels below. 2 Days of Oxidation. Four cores were aged in crude oil with 2 days of oxidation for 96 h using three different crude oil flood rates (see the top left panel of Figure 4). Core C26 obtained a water index of Iw =0.60 when injecting with 1 cm3/h. 3954
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Figure 4. Spontaneous imbibition characteristics for cores aged with variable injection rates at a constant aging time (96 h). Black lines, 1 cm3/h; red lines, 3 cm3/h; blue lines, 5 cm3/h. (Top left) Cores aged in crude oil with 2 days of oxidation (OL = 2 days). (Top right) Core aged in crude oil with 3 days (C33) and 9 days (C29) of oxidation. (Bottom) Cores aged with crude oil oxidation levels over 15 days (OL>15 days).
Core C28 (not shown) was aged to Iw = 0.46 using a 1 cm3/h crude oil injection rate. Flooding with 3 cm3/h, core C31 obtained a water index of Iw = 0.49. Core C32 exhibited a wetting preference of Iw = 0.47 at a 5 cm3/h injection rate. 3 and 9 Days of Oxidation. Two cores were aged with two different crude oil flood rates using crude oil with 3 and 9 days of oxidation (see the top right panel of Figure 4). Flooding with 3 cm3/h, core C29 obtained Iw = 0.25. Increasing the flooding rate to 5 cm3/h lead to a higher water index for core C33 with Iw = 0.40, with 3 days of oxidation. More than 15 Days of Oxidation. Three cores were aged in crude oil with over 15 days of oxidation using three different crude oil flood rates (see the bottom panel of Figure 4). Flooding with 1 cm3/h, core C27 obtained Iw = 0.16. At a 3 cm3/h flood rate, core C30 established a water index of Iw = 0.11. An increased injection rate at 5 cm3/h resulted in an increased water index for core C34 with Iw = 0.28.
similar for all cores (Table 1) and was, for both methods, established by flushing crude oil through the core at a constant flow rate. Comparing average Amott-Harvey water indices for static aging and dynamic aging with similar crude oil properties (same oxidation and filter conditions) shows that the reduction in water-wetness was about the same for 72 h of static aging, with Iw = 0.55 (C9 and C10), and 48 h of dynamic aging, resulting in Iw = 0.61 (C21 and C22). Figure 5 shows the oil recovery curves during spontaneous imbibition for cores C9, C10, C21, and C22. Some distinctive features distinguish the imbibition characteristics for the methods used to establish the reduced wetting preference. The induction time, i.e., the time from exposure to water until the start of oil production for the core, for dynamically aged cores (C21 and C22) was in the range of less than 0.1 h (6 min), whereas the induction time for core plugs aged statically (C9 and C10) was in the range of 1.5-2.0 h. The end points for spontaneous imbibition reflect the variation in wettability (Iw = 0.52-0.66) for the four cores, but production rates were very different. When two cores with equal wetting were compared (C9 and C21, Iw =0.57 and 0.56), the end point for spontaneous imbibition was the same; however, the production rate for static aging was 15 times slower for the first 40% of total recovery. Figure 6 shows the difference between the static aging and dynamic aging of outcrop chalk. The static aging results were previously published in Graue et al.,8 and the dynamic aging results were published by Johannesen.34 Results from this work are also included. Crude oil from the same production
Discussion Static Aging versus Dynamic Aging. The wettability alteration achieved using the dynamic and static wettability alteration procedures was evaluated by averaging the established wetting preferences from each method. Cores C6-C11 were aged statically in crude oil for 72 h, exhibiting a variation in the Amott-Harvey water index between Iw = 0.52 and 77, with an overall average water index of Iw = 0.67. Cores aged dynamically, i.e., continuous injection of crude oil at elevated temperatures, with aging times less than 72 h (C12-C14 and C21-C22), exhibiting a variation in the Amott-Harvey water index between Iw = 0.16 and 0.66, with an average water index of Iw = 0.35. The initial water saturation was
(34) Johannesen, E. B. Ph.D. Dissertation, University of Bergen, Bergen, Norway, 2008.
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for three different aging times (48, 92, and 192 h) and follow the general trend, with slightly lower water indices because of additional oxidation. The greatest change in wettability established during the aging process is believed to be influenced by the degree of contact between the crude oil and the surface of the pore wall, as well as the oil composition. Consider two identical crude oil/brine/rock systems. During static aging, the core is contacted by the crude oil during primary drainage. The surface-active components in the crude oil will interact with the surface, but there is only a limited amount (one mobile oil volume, typically 0.7 PV) of crude oil in the core; i.e., the amount of the surface-active components in the core is limited. In contrast, during dynamic aging, the core is continuously supplied with crude oil components active in the wettability alteration process and would possibly be more efficient. More surface-active components from the crude oil will be consumed by the dynamic aging, and eventually, the aging process will reach equilibrium. The static and dynamic wettability alteration approaches were directly compared using two sister plugs with equal aging time and crude oil.35 Both core plugs were aged for 10 days, one static and one with continuous injection of crude oil from one side. The distribution of wettability was evaluated in situ using NMR T2 measurements. The static average value was 0.38, ranging from 0.35 to 0.40 along the length axis of the core. For dynamic aging, injecting crude oil from one direction only, established an average Iw = 0.09, ranging from 0.2 at the outlet to 0.02 at the inlet. In the case when the core is submerged in crude oil after drainage, a frequently used procedure to age the core plugs, a radially, non-uniformly distributed wettability preference, may be established in the core.10 In this procedure, the surface of the core will be contacted by bulk crude oil in the container, where potential wettability altering components are in abundance. The transport of active components from bulk crude oil on the surface toward the interior of the core is related to diffusion through the pore space and will be slow. In the interior of the core, there will be a limited amount of surfaceactive components in the crude oil to alter the wettability. This results in a non-uniform wettability distribution within the core, with more aging taking place in the circumference of the core plug and lesser aging along the inner central axis of the core plug. The radial wettability distribution during static aging was verified by Spinler et al.10 and Aspenes et al.28 by imaging the spatial distributed water saturation at Swi, after spontaneous imbibition of water, Swsp, and after forced water-flood, Swf, to calculate the spatially distributed local Amott-Harvey water index in three dimensions using magnetic resonance imaging (MRI). The circumference of the plug was rendered almost neutral-wet, while the interior remained strongly water-wet. Optimal Aging Conditions for Laboratory Wettability Alteration. During E&O, the lighter components in the crude oil evaporate from the bulk crude oil, hence increasing the relative amounts of the heavier components in the crude oil, such as asphaltenes. The level crude oil oxidation at 90 °C was shown to impact the change in wettability for a given aging time (see Figure 7). Five cores were aged for 48 h using a 3 cm3/h injection rate, at the same initial water saturation.
Figure 5. Comparing production rates and induction times for four cores with similar average Amott-Harvey indices but aged with either dynamic (C21 and C22) or static (C9 and C10) aging methods. A statically aged core exhibits longer induction times and slower production rates.
Figure 6. Average Amott-Harvey water indices as a function of the aging time established during static aging8 and dynamic aging34 in chalk, previously reported. The results show that the greatest change in wettability is established with dynamic aging, and the difference between static aging and dynamic aging increases with increasing aging times. Results from this study follow the general trend, with slightly lower water indices because of additional oxidation.
well was used to age all core plugs. The crude oil was filtered through a chalk core prior to being used as an aging fluid. The chalk cores were drained to Swi in a bidirectional crude oil injection at constant differential pressure. At least 2 PV of crude oil was injected during primary drainage. At static conditions, the core was stored in closed oil-filled containers for different lengths of time at irreducible water saturations (Swi ∼ 0.20-0.25). At dynamic conditions, the crude oil was injected through the core at low rates (1.5 cm3/h for 1.5 in. cores and 3 cm3/h for 2.0 in. cores). At the end of aging, the crude oil was flushed from the core by injecting 5 PV decaline and 5 PV decane. Average static Amott-Harvey indices based on 19 cores aged statically with 0-31 days of aging time and average dynamic Amott-Harvey indices based on 45 cores aged dynamically with 0-12 days of aging time are shown in Figure 6. Dynamic aging shows greater changes in wetting for aging times longer than 6 days and establishes lower Amott-Harvey water indices than static aging. A disadvantage with dynamic aging is greater crude oil consumption during aging. Dynamic aging results from this work are included
(35) Johannesen, E.; Howard, J. J.; Graue, A. Proceedings of the International Symposium of the Society of Core Analysts; Abu Dhabi, United Arab Emirates (UAE), Oct 28-Nov 03, 2008.
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Figure 7. Influence of crude oil E&O at 90 °C on the wetting change during dynamic aging. Five cores (C12, C13, C14, C21, and C22) were aged at an identical time (48 h) and injection rate (3 cm3/h). The established Amott-Harvey water indices ranged from Iw = 0.16 to 0.66, reflecting the crude oil E&O, which varied from 0 to 7 days.
Figure 8. Comparison of two dynamic aging procedures: a constant injection rate and a constant aging time as a function of PV injected. The constant injection rate tests (blue squares) showed a decreasing Amott-Harvey water index for increasing times: 48, 96, and 192 h. In the constant aging time tests, there is an optimal injection rate that reduces the Amott-Harvey water index most efficiently.
Dependent upon the level of oxidation of the crude oil, the wettability, expressed as the Amott-Harvey water index, ranged from Iw =0.16-0.66. The same trend was observed at other injection rates and aging times. Although the results show a strong correlation between time allowed for oxidation and the change in wettability during aging, the picture is likely to be more complicated than a simple relationship between the increased relative amounts of heavier components in the crude oil and aging efficiency. Correlations based on oil composition only, including asphaltene content, show only limited success in predicting the tendency for crude oil to alter the wetting preference of the rock.36 Experiments with deasphalted crude oil do not produce an appreciable wettability change as compared to original crude oil,37 and it is likely that asphaltenes are therefore only partly responsible for wettability alteration.24 According to Buckley,38 the absolute content of asphaltenes in the crude oil has less importance to the efficiency of wettability alteration than the presence of the more soluble resins that help to solubilize the largest molecules. The absence of low-molecular-weight components that destabilize asphaltenes is also important for the change in wettability of the rock surface.38 The amount of the lighter components in the crude oil was reduced during evaporation and may explain the increased wettability alteration ability of this crude oil. The change in the chemical property of the crude oil during the E&O process was not quantified in a chemical analysis. The variation in aging time, the applied injection rates, and the level of crude oil oxidation influenced the wetting preference established during the aging process. Two dynamic aging approaches, with a continuous supply of the active components in the crude oil, were preferred over static aging because of concerns including chromatographic separation of crude oil, heterogeneous adsorption, and non-uniformly wettability preferences related to static aging.10,27,35,39 Figure 8 shows the aging results for two dynamic aging conditions:
a constant injection rate (3 cm3/h) with different aging times and a constant aging time (96 h) with different crude oil injection rates. The constant injection rate tests with variable aging times (blue squares) showed a decreasing AmottHarvey water index for increasing aging times of 48, 96, and 192 h. In the constant aging time group (96 h), the average water index using 1 cm3/h was Iw = 0.53 (C26 and C28), higher than cores aged with 3 cm3/h at Iw = 0.31 (C16, C17, and C32). During the slow injection (1 cm3/h), a total of 1.3 PV of crude oil was injected through the core, compared to 3.8 PV for a 3 cm3/h injection rate. On the basis of the fast adsorption of surface-active components in the crude, it is likely that the limited supply of these components resulted in a less efficient aging during the low injection rate. If this is true, the efficiency should increase if additional pore volumes of crude oil were injected during the same time interval. However, this was not the case during the 5 cm3/h injection rate group, with an average water index of Iw = 0.44 (C32 and C33). The level of crude oil E&O was similar (2 or 3 days) for all cores. This suggests that the crude oil injection rate influences the bulk/surface crude oil interactions active in the wettability alteration process. The diameter, length, and porosity for all cores used in this study vary only slightly, and the optimal crude oil injection rate must be scaled properly when applied to cores with other diameters, lengths, and porosities. Although beyond the scope of this work, injection rate scaling must also be extrapolated to include pore geometry, because the surface area will influence adsorption and, therefore, the optimal conditions for aging. It is also well-known that silica and carbonate have different surface charges and attract different components in the crude oil, and the results obtained may not be directly applicable to sandstone or rocks with different surface charges. Conclusions (1) Three crude-oil-based aging techniques have been applied to outcrop chalk samples to alter the wettability from strongly water-wet. The obtained wetting preference varied from strongly water-wet (Iw = 1.0) to near-neutral-wet (Iw = 0.06). The Amott-Harvey oil index was zero for all cores. The established wettability condition was highly sensitive to the method used. (2) It was shown that static aging, i.e., aging in a
(36) Cuiec, L. Proceedings of the 21st Intersociety Energy Conversion Engineering Conference; San Diego, CA, 1986. (37) Buckley, J. S.; Morrow, N. R. Characterization of crude oil wetting behavior by adhesion tests. Proceedings of the Society of Petroleum Engineers (SPE)/Department of Energy (DOE) Enhanced Oil Recovery Symposium; Tulsa, OK, 1990. (38) Buckley, J. S. SPE Adv. Technol. Ser. 1995, 3 (1), 53–59. (39) Standnes, D. C.; Austad, T. J. Pet. Sci. Eng. 2000, 28, 111–121.
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limited amount of crude, was less effective than dynamic aging, i.e., continuous flooding of crude oil. For short aging times (72 h or less), static aging and dynamic aging performed equally well. For longer aging times (up to 12 days), the dynamic approach more effectively reduced the wettability of the chalk, in terms of both the Amott-Harvey water index and the time needed to reduce water-wetting. (3) The oxidation of a light North Sea crude oil (API=27°) changed the relative composition of the crude oil and influenced the ability of the crude oil to alter the wettability. A chemical analysis to quantify changes was not performed, but anecdotal evidence shows that crude oil batches with long E&O times exhibited the greatest change in the wetting preference toward less water-wet conditions. (4) For constant crude oil injection rates, the established wetting preference decreased with increasing aging times. The efficiency in aging decreased exponentially with time. (5) At a constant aging time, an optimal crude oil injection rate exists that alters the wettability most efficiently with respect to pore volumes injected and obtained wetting preference.
Nomenclature AN = acid number (mg of KOH/g of oil) API=American Petroleum Institute gravity [API gravity= (141.5FH2O/Foil)/131.5] (deg) BN = base number (mg of KOH/g of oil) cm3 = mL cP = viscosity, centipoise (SI: 1 cP = 1 mPa s) Iw = Amott-Harvey water index OIP = oil in place (mL) PV = pore volume (mL) Rf = recovery factor (fraction of OIP) RI = refractive index Swi = initial water saturation (fraction of PV) Sw_spont = water saturation after spontaneous imbibition (fraction of PV) Sw_wf = water saturation after forced imbibition (fraction of PV) wt % = weight percent
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