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Wettability alteration in chalk
Journal of Petroleum Science and Engineering 28 Ž2000. 111–121 www.elsevier.nlrlocaterjpetscieng
Wettability alteration in chalk 1. Preparation of core material and oil properties Dag C. Standnes, Tor Austad ) StaÕanger College, Rogaland UniÕersity, P.O. Box 2557, Ullandhaug, N-4004 StaÕanger, Norway Received 2 February 2000; accepted 26 July 2000
Abstract A reproducible method has been developed to create homogeneous oil-wet chalk material wettability with and without initial water saturation. This was accomplished by aging crude oil-saturated chalk cores for different time intervals and at different temperatures. A total of five different crude oils were tested for their potential to alter the wetting properties of the chalk material. Chemical analysis of the crude oils showed that the potential for wettability alteration correlated with the amount of acidic components in the crude oil, as measured by their acid number ŽAN.. The wettability of the chalk was evaluated by their ability to spontaneously imbibe synthetic brine. There was no sign of water imbibition into cores without initial water saturation after 5 weeks, while cores with an initial water saturation of 23% imbibed about 9% of water during 8 weeks at 408C. q 2000 Elsevier Science B.V. All rights reserved. Keywords: imbibition; chalk; wettability; oil recovery
1. Introduction Spontaneous imbibition of water into low permeability Ž0.1–10 mD. matrix blocks of a fractured chalk reservoir is considered to be an important method for optimal secondary oil recovery from this type of oil reservoir, as verified by the Ekofisk field in the North Sea ŽThiebot et al., 1990; Thomas et al., 1987; Torsæter, 1984.. The success is, however, highly dependent on the wetting state of the reservoir rock. Both laboratory experiments and field tests have shown that water-wet and mixed-wet chalk material appears to imbibe water quite well due to )
Corresponding author. E-mail addresses: [email protected] ŽD.C. Standnes., [email protected] ŽT. Austad..
the large positive capillary pressure ŽAustad and Milter, 1997; Cuiec et al., 1994; Downs and Hoover, 1989; Jadhunandan and Morrow, 1991.. Spontaneous imbibition of water is not regarded as an improved oil recovery method under oil-wet conditions because of the low value of the capillary pressure Žnegative or slightly positive.. Such displacement of the wetting oil phase by water must then be described as a drainage process, which is normally performed by viscous or gravity forces. Normally, it is not physically possible to displace the oil in this way in a realistic production process of a fractured low-permeability reservoir. Recently, it was demonstrated by laboratory experiments that a certain surface-active material added to the water was able to change the wettability from nearly oil-wet to water-wet, thereby creating a spon-
0920-4105r00r$ - see front matter q 2000 Elsevier Science B.V. All rights reserved. PII: S 0 9 2 0 - 4 1 0 5 Ž 0 0 . 0 0 0 8 3 - 8
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
112
Table 1 Oil used in the experiments
v
Oil
Pretreatment
A B C D Ea Fa
Pure n-heptane Ekofisk stock tank oil filtered through 3-mm filter Oil from BP; diluted 1:1 with n-heptane Asphaltenic oil; diluted 1:1 with n-heptane Oil from Statoil; 70:30 crude oil: n-heptane Oil from Statoil; 60:40 crude oil: n-heptane a
v
v
homogeneous distribution of surface active material from the crude oil in the core material; aging conditions Žtime and temperature.; and initial water saturation.
2. Experimental
Different initial crude oils.
2.1. Material taneous imbibition of the aqueous phase, displacing the oil ŽAustad et al., 1998.. About 70% of oil in place was recovered. It is also of interest to note that as much as 80% of all the carbonate reservoirs can be classified as neutral to oil-wet ŽDowns and Hoover, 1989.. The present paper is part of a project to study the chemical mechanism behind the change of wettability, from oil-wet to water-wet, in low-permeability chalk using surface active agents in the water phase. In order to do realistic imbibition experiments on a small core, it is very important to be able to obtain a homogeneous wettability state throughout the core. Otherwise, it is hard to interpret the imbibition profiles. In this first paper, we will present details on how to prepare the chalk in order to obtain homogeneous oil-wet core material for further studies. Important factors influencing the wettability state of the chalk are: v
chemical properties of the crude oil Žasphaltenes, resins, acid, and base number.;
2.1.1. Oil Six different oil phases were used. Pretreatment and descriptions are given in Tables 1 and 2. Most of the crude oils were mixed with n-heptane in different ratios in order to lower the viscosity of the oil. No separation of asphaltenes was noticed. 2.1.2. Brine Synthetic injection water containing 44.94 grl of total dissolved solid was used. The composition is given in Table 3. pH, density, and viscosity at 408C are 8.0, 1.02 grcm3 and 0.8 cP, respectively. 2.1.3. Chalk Outcrop rock samples from the Stevns Klint near Copenhagen, Denmark, were used as porous media ŽFrykman, 1994.. Air permeability and porosity of the core material were in the range 2–7 mD and 44.3–53.8%, respectively. The core dimensions used in the imbibition experiments are listed in Tables 4 and 5.
Table 2 Properties of the oils used Oil
Density Ž208C, grcm3 .
AN a Žmg KOHrg oil.
Wax-formation temperaturea Ž8C.
Asphaltenesb Žwt.%.
IFT Ž208C, mNrm.
A B C D E F
0.684 0.835 0.815 0.798 0.846 0.816
– 0.12 0.52 0.055 0.41 1.73
– 29 53 33 22 25–30
0.90 0.33 2.57 0.19 0.23
55.4 19.8 20.3 28.1 15.7 15.4
a b
The values are related to the respective initial crude oils. The values are related to the actual oils used.
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121 Table 3 Brine composition Component
2.3. Saturation procedures Concentration Žgrl.
q
Na Kq Ca2q Mg 2q Cly SO42y HCOy 3 Total
113
Two systems were studied, i.e. cores with 100% initial oil saturation and cores with irreducible brine saturation.
12.14 0.25 3.43 0.93 26.54 1.56 0.09 44.94
2.2. Analysis 2.2.1. Asphaltenes The amount of asphaltene in the oil samples was determined by the following procedure: 10.0 ml of oil was mixed with 400 ml of n-heptane in a closed beaker. The mixture was stored overnight at 58C and then filtered through 0.45-mm filter. The filter was dried at 508C and weighed. The weight percent of asphaltenes could then be calculated from the mass of the precipitate. 2.2.2. Interfacial tension The interfacial tension at 208C between equilibrated equal volumes of brine and oil was determined using a duNouy tensiometer.
2.3.1. 100% oil saturation Prior to imbibition tests, the cores were handled in different ways in order to establish a method that creates a uniform wettability state. In all cases, the cylindrical cores were first dried up at 908C to constant weight. They were then placed in a container, evacuated, and surrounded with oil. The cores rested in the oil for 2 h and the porosity could then be calculated from the weight difference, bulk volume, and oil density. Thereafter, the following procedures were used prior to the imbibition tests at 408C. 2.3.1.1. Procedure 1. The cores were aged in a closed container filled with oil for 4 days at 508C. The volume ratio between the core and the oil was about 2 during the aging process. 2.3.1.2. Procedure 2. The cores were placed in Hassler core holders, flooded with at least 1 PV of oil in each direction, with a confining pressure not exceeding 33 bar, and finally aged for 4 days at 508C in a closed container surrounded with oil of the same volume ratio as described in Procedure 1.
Table 4 Experimental data for the different imbibition systems Test
Oil
Saturation procedure
Core a height, diameter Žcm.
1 2 3 4 5 6 7 8 9
A A B B B C D E F
1 1 1 1 3 2 3 3 3
2.72, 3.80 3.20, 3.80 5.00, 3.70 5.10, 3.80 5.64, 3.80 5.48, 3.83 5.58, 3.84 6.70, 3.82 5.85, 3.83
a
Before removing the outer layer. After removing the outer layer.
b
Core b height, diameter Žcm.
5.00, 3.46 4.74, 3.46 5.97, 3.45 5.38, 3.52
Porosity f Ž%.
PV Žcm3 .
53.3 53.8 49 48 50.5 47.7 43.5 45.8 44.9
16.43 19.53 26.40 27.72 23.74 21.26 28.11 25.56 23.51
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
114
Table 5 Experimental data for the system with initial water saturation Test
Oil
Saturation procedure
Core a height, diameter Žcm.
Core b height, diameter Žcm.
Porosity Ž%.
S wi Ž%.
PV Žcm3 .
HCPV Žcm3 .
10
F
4
5.71, 3.83
5.05, 3.46
46.4
23.0
22.032
16.965
a
Before removing the outer layer. After removing the outer layer.
b
2.3.1.3. Procedure 3. Similar to Procedure 2, but in addition, the outermost layer Ž2 mm. of the core was removed by shaving off the cores in a lathe just before the imbibition tests. 2.3.2. Irreducible water saturation 2.3.2.1. Procedure 4. The cylindrical core was dried at 908C to constant weight and placed in a container, evacuated, and surrounded with brine. The material rested in the brine for 2 h and the porosity was then calculated from the weight difference, bulk volume, and brine density. The core was then placed in a Hassler core holder and flooded with at least 1 PV of oil in each direction, with a confining pressure not exceeding 25 bar. The porous medium was aged for 1 month at 908C in a closed container surrounded with oil, with the same ratio between core volume and oil volume as in Procedure 1. The outermost layer Ž2 mm. of the core was removed by shaving off the core in a lathe just ahead of the imbibition test. 2.4. Imbibition experiments The imbibition experiments were conducted in standard Amott cells at 408C. The oil-saturated cores were placed in a vertical position and surrounded by 350 cm3 of brine. The volume of oil produced was measured as a function of time.
tive or relative assessment of the wettability state of similar core material can be obtained by comparing the spontaneous imbibition rate of water ŽJadhunandan and Morrow, 1991; Graue et al., 1998.. In general, the imbibition rate decreases as the degree of oil wettability increases. This procedure, which requires a homogeneous wettability state of the core, was used in this paper to classify the relative wettability state of the different systems. As far as the the scope of the present paper is to work out a technique to obtain homogeneously wetted chalk cores, the reported imbibition results have not been further analysed in terms of dimensionless time for scaling the imbibition ŽMa et al., 1997.. The chemical properties of the functional groups of the surface active material in the crude oil Žespecially asphaltenes and resins. are crucial with regard to the ability to adsorb onto the chalk material. Compared to sandstone, the chalk is much more homogeneous in mineral composition, and therefore, the wetting state of the porous material should be more uniform. The high-molecular-weight polar components will, depending on rock type, initial water saturation, crude oil type, aging temperature and time, alter the wetting properties of the mineral surface towards a more oil-wet state ŽAnderson, 1986; Buckley, 1996; Cuiec, 1984; Denekas et al., 1959; Graue et al., 1994, 1998; Jadhunandan and Morrow, 1991; Milter, 1996; Zhou et al., 1995.. 3.1. 100% oil-saturated chalk
3. Results and discussion Unfortunately, no universal method exists to determine the wettability state of porous media. The most common method to obtain quantitative information is to perform an Amott test, and calculate the Amott–Harvey index ŽAnderson, 1986.. A qualita-
The repeatability of the imbibition was tested by using a water-wet system, i.e. n-heptane as the oil phase, as shown in Fig. 1. The cores were saturated according to Procedure 1. As shown in the figure, the oil production curves were quite reproducible for the two core samples, confirming good repeatability.
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
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Fig. 1. Spontaneous imbibition of brine into chalk cores containing 100% n-heptane Žoil A. at 268C.
It is also indicated from the experiments that the core material appeared to be homogeneous and initially water wet. 3.1.1. Homogeneous wettability Using oil B, i.e. the Ekofisk stock tank oil, and treating the cores according to Procedure 1 Žno flooding of the core., the imbibition profiles for two different cores are shown in Fig. 2. There was no oil expulsion during the first 600 min. The oil production that was initiated after f 600 min took place at a very slow rate, but later on Žafter 1600 min f 1 day., the production rate increased strongly and maximum oil recovery of approximately 74% was achieved within 1.5 weeks. It was observed that the oil was displaced equally from the total surface of the core, indicating a countercurrent flow between the imbibed and displaced fluids governed by capillary forces. The accelerating oil recovery may indicate the existence of a wettability gradient from nearly oil wet at the surface to water wet towards the centre of the core. This assumption was confirmed when cleaving the core after the experiment. The gradient in the colour, which is related to the residual oil and ad-
sorbed surface active material, showed a significant change from dark to light when moving from the boundary of the core towards the centre, as seen in Fig. 3. It must be noticed that porosity calculations based on weight differences clearly verified that the cores were initially totally saturated with the oil.
Fig. 2. Spontaneous imbibition of brine into cores saturated with oil B and treated according to Procedure 1.
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D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
Fig. 3. Picture of the cleaved core Žtest 3. after finishing the spontaneous imbibition process.
Thus, it seems likely that the oil undergoes a chromatographic separation of coloured surface active components as the oil flows into the chalk material during the saturation procedure. The adsorption of surface active components must be very fast, and the oil reaching the central parts of the core is more or less depleted in these components. The result is a wettability gradient inside the core from nearly oil wet at the surface to more water wet in the centre. Two more experiments were carried out to further confirm this hypothesis. In the first experiment, a core saturated with oil F, and treated according to Procedure 1, was cleaved directly after the saturation process was finished, i.e. prior to any imbibition test. As shown in Fig. 4, a colourless fluid is present in the central parts of the core, confirming the existence of a chromatographic separation of coloured surface active material in the oil. In the second experiment, oil B was allowed to pass through a thin glass pipette packed with chalk powder. The first oil drops leaving the capillary of the pipette was colourless, i.e. free from the heavy end fraction of the crude oil. From the present observations, it is very difficult to obtain uniform wettability in the chalk material by just treating the core material according to Procedure 1. In order to obtain a uniform compositional distribution of oil components in the core material, the cores were placed in Hassler core holders and flooded with at least 1.0 PV of oil in each direction, as given
in Procedure 2. It is difficult to do a viscous flooding of fluid through low-permeable chalk with very high porosity Žnearly 50%.. A rather low confining pressure must be applied in order to avoid cracking of the core material. During the aging process, the core is surrounded by fresh crude oil, and a large amount of surface active components from the oil will adsorbrdeposit onto the outermost surface of the core. This may not be representative for the general wetting state for other parts of the core. The wettability induced by the crude oil inside the porous media is restricted by the amount of surface active components residing in the pore volume, because there is limited supply of fresh crude oil here during the aging process. The effect is illustrated in Fig. 5. The core was incised to different depths. The water was imbibed into the cross-sections with the smallest diameter, where the chalk material was most water wet, and the oil was expelled from the dark oil-wet areas, which had been in contact with fresh crude oil during the aging period. It was therefore decided that the outer layer Žabout 2 mm at all surfaces. be removed prior to the imbibition experiments, as in Procedure 3. The result from the imbibition test after the core was treated according to this procedure is shown in Fig. 6. The general feature of the imbibition profile revealed no indication of a wettability gradient inside the core material. This was confirmed when the core was cleaved after the imbibition experiment, as shown in
Fig. 4. Picture showing the compositional gradient of oil F if the core is treated according to Procedure 1, prior to any imbibition test.
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
Fig. 5. Imbibition of water into a core saturated with oil B according to Procedure 2, and cut in different cross-sections.
Fig. 7. The residual oil and adsorbed surface active compounds seemed to be evenly distributed in the core material in sharp contrast to the core, which was treated according to Procedure 1. Thus, in the following experiments, the cores were treated as described in Procedure 3. 3.1.2. Wettability related to oil properties As the present paper is part of a project to study wettability alteration Žoil-wet to water-wet. in chalk
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Fig. 7. Picture showing that residual oil and adsorbed surface active compounds seem to be evenly distributed in the core of the cleaved core at the end of water imbibition.
using surface active chemicals, it is necessary to be able to create homogeneous oil-wet core material within a reasonable time in the laboratory. It is documented in the literature that asphaltenes and resins are the most active fractions of the crude oil concerning wettability alterations of mineral surfaces ŽBuckley, 1996.. However, experimental data so far show no clear correlation between the asphaltener resin content and the crude’s ability to make the mineral surface oil wet, other than the fact that these
Fig. 6. Imbibition profile for a core handled according to Procedure 3.
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D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
materials must be present in the crude oil. Buckley Ž1996. has pointed out four different mechanisms, which can alter an original water-wet surface to an oil-wet state. The most important mechanism in the case of dry surfaces is the polar interaction between acid and base components in the oil and the mineral surface. She noticed that the wettability change caused by this interaction was found to be very fast, and after the modification of the surface, the contact angle was almost constant as a function of time. The rapid rate by which polar components were adsorbed into the chalk surface was also confirmed in our case. Imbibition tests, after treating the cores according to Procedure 3, for the different oils are presented in Fig. 8. The imbibition rates are significantly reduced in comparison with the imbibition profile for the water-wet core, oil A. This confirmed that all crude oils, to varying degrees, have the ability to modify the mineral surface. As can be seen, there is a broad range of rates by which the different cores imbibe the brine spontaneously. The data show, however, that there is a correlation between the acid number ŽAN. and the ability to alter the wetting state of the porous media, as measured by spontaneous imbibition of brine. High AN seems to provoke a stronger
modification of the mineral surface towards more oil wet. This is in line with the suggestions put forward by Buckley Ž1996. that polar interactions are the most important mechanism for wettability change in the absence of initial water in the porous media. It is quite evident from the figure that oil F, which has the highest AN Ž1.73 mg KOHrg., appeared to give the most oil-wetted state, i.e. no imbibition of water was detected even after 33 days. No such correlation exists between the imbibition rates and the content of asphaltenes for the different crude oils. Note that oil D, which has an asphaltene content of about 2.6 wt.%, imbibes water quite well. In this case, the asphaltenic material contains a small number of acid groups ŽAN s 0.055 mg KOHrg., and it has a low adsorption potential towards the chalk surface. Very often, a positive correlation between the AN and the amount of asphaltenes is observed for different oils, but the functional acid groups need not be part of the asphaltene fraction ŽSkauge et al., 1999.. Likewise, in our case, we have an oil with relatively high asphaltenic content and a relatively low AN. The AN and the content of asphaltenes for oils E and C are comparable, 0.41 mg KOHrg, 0.19 wt.% and 0.52 mg KOHrg and 0.33 wt.%, respectively.
Fig. 8. Spontaneous imbibition of brine into chalk cores saturated with different crude oils according to Procedure 3.
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
The difference in the imbibition rate for the two cases is, however, unreasonably large. The core saturated with oil C has a very low imbibition rate and it acts nearly as oil wetted. The wax precipitation temperature for the initial crude oil is as high as 538C, shown in Table 2, and it is reasonable to believe that the reduced ability for brine imbibition can be partly ascribed to some kind of blocking effect due to precipitation of wax material in the porous media. It was noticed that wax precipitated from the actual oil at room temperature. Thus, in further wettability alteration studies by imbibition of surface active material, it is important to work with systems free from precipitated organic material in the porous medium. It is concluded that oil F has the ability to change the wettability of the chalk core from water wet to oil wet. The wax-formation temperature of the initial crude oil is about 25–308C, which excludes wax precipitation during the imbibition tests. The oil is stable, and no sign of any precipitate was observed after long-time storage at room temperature. It is further concluded that the negatively charged carboxyl groups are the most active polar functional groups of the crude oil in adsorbing organic material onto the chalk surface. This is also in line with adsorption studies by Thomas et al. Ž1993., stating that carboxylic acids adsorb most strongly, and essentially irreversibly, onto carbonates.
119
difficult to get very low initial water saturation by this method. Nevertheless, we used this last method in this work, and the initial water saturation was calculated to be 23%, as given in Table 4. Fig. 9 shows the imbibition profile for a core saturated with oil F and prepared according to Procedure 4. In contrast to the 100% oil-saturated cores, about 7% of the OOIP was displaced by a fast spontaneous imbibition of water. Later, some oil was displaced from the core, amounting to about 9% of OOIP after 8 weeks. The fast expulsion of oil is not related to thermal expansion of the fluids inside the core due to the experimental technique because this is not observed for the 100% oil-saturated cores. Contrary to the 100% oil-saturated cores, the wettability alteration of the chalk core with initial water saturation of 23% must be somewhat inhomogeneous. The outermost part of the core appears to be more water wet. This can be explained due to end effects related to the saturation procedure used to establish residual water saturation. There may be a gradient in the oil saturation close to the surface of the core, i.e. a decrease in the oil saturation. Consequently, the amount of surface active material in this region will decrease, and the chalk will become more water wet. Eventhough 2 mm of the core material was shaved off, this is probably not enough to create a homogeneously oil-wetted core.
3.2. Initial irreducible brine saturation The centrifuge technique has previously been used by Torsæter Ž1984. and Austad et al. Ž1998. to establish initial or irreducible water saturation in reservoir chalk cores from the Ekofisk formation. The cores must be handled carefully in the centrifuge in order to avoid cracking during the centrifuge process. Initial water saturations in the range 20–25% were obtained in this way. For small cores and low-viscosity fluids, it is also possible to perform coreflooding in Hassler cells, ŽGraue et al., 1994, 1998.. Due to the low confining pressure of 25 bar, the flow rate of the oil to generate S wi must be very low, which will give low viscous forces acting on the water phase. Thus, it will be
Fig. 9. Spontaneous imbibition of brine into chalk material at irreducible brine saturation.
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D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
4. Conclusion The following are some general conclusions. v
v
v
v
The adsorption of surface active components onto a dry chalk surface is a rather fast process. Components from the crude oil undergo chromatographic separation during the saturation, as in Procedure 1. In this case, the cores were placed in a container, evacuated, surrounded with oil, and aged for 4 days at 508C. In order to obtain a homogeneous wetting state in the chalk material, it is recommended to oil-flood the core in each direction and remove the outermost layer after aging the core in the actual crude oil. The method can be used for 100% oil-saturated cores and cores with initial water saturation, taking into account the end effects in the latter case. The wettability induced by the crude oils on chalk surfaces is related to the amount of acidic components in the crude oil, i.e. crude oils with high AN have a greater potential to turn the chalk oil wet. It was also noticed that the amount of asphaltenes in the crude oil is not directly related to the potential for turning the chalk oil wet.
Nomenclature AN Acid number Žmg KOHrg oil. BN Base number Žmg KOHrg oil. HCPV Hydrocarbon pore volume Žcm3 . IFT Interfacial tension ŽmNrm. OOIP Original oil in place PV Pore volume Žcm3 . S wi Initial water saturation Žfraction, %. vol.% Volume percent wt.% Weight percent f Porosity Žfraction, %. m Viscosity ŽcP. r Density Žgrcm3 . s IFT ŽmNrm.
Acknowledgements This study was financed by the Norwegian Research Council ŽNFR.. In addition, the authors wish
to thank Phillips Petroleum and Statoil for providing oil samples, and Dan Olsen, GEUS Copenhagen Denmark, for providing the chalk material. Thanks also to Skule Strand for invaluable support during the experimental work.
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Wettability alteration in chalk 1. Preparation of core material and oil properties Dag C. Standnes, Tor Austad ) StaÕanger College, Rogaland UniÕersity, P.O. Box 2557, Ullandhaug, N-4004 StaÕanger, Norway Received 2 February 2000; accepted 26 July 2000
Abstract A reproducible method has been developed to create homogeneous oil-wet chalk material wettability with and without initial water saturation. This was accomplished by aging crude oil-saturated chalk cores for different time intervals and at different temperatures. A total of five different crude oils were tested for their potential to alter the wetting properties of the chalk material. Chemical analysis of the crude oils showed that the potential for wettability alteration correlated with the amount of acidic components in the crude oil, as measured by their acid number ŽAN.. The wettability of the chalk was evaluated by their ability to spontaneously imbibe synthetic brine. There was no sign of water imbibition into cores without initial water saturation after 5 weeks, while cores with an initial water saturation of 23% imbibed about 9% of water during 8 weeks at 408C. q 2000 Elsevier Science B.V. All rights reserved. Keywords: imbibition; chalk; wettability; oil recovery
1. Introduction Spontaneous imbibition of water into low permeability Ž0.1–10 mD. matrix blocks of a fractured chalk reservoir is considered to be an important method for optimal secondary oil recovery from this type of oil reservoir, as verified by the Ekofisk field in the North Sea ŽThiebot et al., 1990; Thomas et al., 1987; Torsæter, 1984.. The success is, however, highly dependent on the wetting state of the reservoir rock. Both laboratory experiments and field tests have shown that water-wet and mixed-wet chalk material appears to imbibe water quite well due to )
Corresponding author. E-mail addresses: [email protected] ŽD.C. Standnes., [email protected] ŽT. Austad..
the large positive capillary pressure ŽAustad and Milter, 1997; Cuiec et al., 1994; Downs and Hoover, 1989; Jadhunandan and Morrow, 1991.. Spontaneous imbibition of water is not regarded as an improved oil recovery method under oil-wet conditions because of the low value of the capillary pressure Žnegative or slightly positive.. Such displacement of the wetting oil phase by water must then be described as a drainage process, which is normally performed by viscous or gravity forces. Normally, it is not physically possible to displace the oil in this way in a realistic production process of a fractured low-permeability reservoir. Recently, it was demonstrated by laboratory experiments that a certain surface-active material added to the water was able to change the wettability from nearly oil-wet to water-wet, thereby creating a spon-
0920-4105r00r$ - see front matter q 2000 Elsevier Science B.V. All rights reserved. PII: S 0 9 2 0 - 4 1 0 5 Ž 0 0 . 0 0 0 8 3 - 8
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
112
Table 1 Oil used in the experiments
v
Oil
Pretreatment
A B C D Ea Fa
Pure n-heptane Ekofisk stock tank oil filtered through 3-mm filter Oil from BP; diluted 1:1 with n-heptane Asphaltenic oil; diluted 1:1 with n-heptane Oil from Statoil; 70:30 crude oil: n-heptane Oil from Statoil; 60:40 crude oil: n-heptane a
v
v
homogeneous distribution of surface active material from the crude oil in the core material; aging conditions Žtime and temperature.; and initial water saturation.
2. Experimental
Different initial crude oils.
2.1. Material taneous imbibition of the aqueous phase, displacing the oil ŽAustad et al., 1998.. About 70% of oil in place was recovered. It is also of interest to note that as much as 80% of all the carbonate reservoirs can be classified as neutral to oil-wet ŽDowns and Hoover, 1989.. The present paper is part of a project to study the chemical mechanism behind the change of wettability, from oil-wet to water-wet, in low-permeability chalk using surface active agents in the water phase. In order to do realistic imbibition experiments on a small core, it is very important to be able to obtain a homogeneous wettability state throughout the core. Otherwise, it is hard to interpret the imbibition profiles. In this first paper, we will present details on how to prepare the chalk in order to obtain homogeneous oil-wet core material for further studies. Important factors influencing the wettability state of the chalk are: v
chemical properties of the crude oil Žasphaltenes, resins, acid, and base number.;
2.1.1. Oil Six different oil phases were used. Pretreatment and descriptions are given in Tables 1 and 2. Most of the crude oils were mixed with n-heptane in different ratios in order to lower the viscosity of the oil. No separation of asphaltenes was noticed. 2.1.2. Brine Synthetic injection water containing 44.94 grl of total dissolved solid was used. The composition is given in Table 3. pH, density, and viscosity at 408C are 8.0, 1.02 grcm3 and 0.8 cP, respectively. 2.1.3. Chalk Outcrop rock samples from the Stevns Klint near Copenhagen, Denmark, were used as porous media ŽFrykman, 1994.. Air permeability and porosity of the core material were in the range 2–7 mD and 44.3–53.8%, respectively. The core dimensions used in the imbibition experiments are listed in Tables 4 and 5.
Table 2 Properties of the oils used Oil
Density Ž208C, grcm3 .
AN a Žmg KOHrg oil.
Wax-formation temperaturea Ž8C.
Asphaltenesb Žwt.%.
IFT Ž208C, mNrm.
A B C D E F
0.684 0.835 0.815 0.798 0.846 0.816
– 0.12 0.52 0.055 0.41 1.73
– 29 53 33 22 25–30
0.90 0.33 2.57 0.19 0.23
55.4 19.8 20.3 28.1 15.7 15.4
a b
The values are related to the respective initial crude oils. The values are related to the actual oils used.
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121 Table 3 Brine composition Component
2.3. Saturation procedures Concentration Žgrl.
q
Na Kq Ca2q Mg 2q Cly SO42y HCOy 3 Total
113
Two systems were studied, i.e. cores with 100% initial oil saturation and cores with irreducible brine saturation.
12.14 0.25 3.43 0.93 26.54 1.56 0.09 44.94
2.2. Analysis 2.2.1. Asphaltenes The amount of asphaltene in the oil samples was determined by the following procedure: 10.0 ml of oil was mixed with 400 ml of n-heptane in a closed beaker. The mixture was stored overnight at 58C and then filtered through 0.45-mm filter. The filter was dried at 508C and weighed. The weight percent of asphaltenes could then be calculated from the mass of the precipitate. 2.2.2. Interfacial tension The interfacial tension at 208C between equilibrated equal volumes of brine and oil was determined using a duNouy tensiometer.
2.3.1. 100% oil saturation Prior to imbibition tests, the cores were handled in different ways in order to establish a method that creates a uniform wettability state. In all cases, the cylindrical cores were first dried up at 908C to constant weight. They were then placed in a container, evacuated, and surrounded with oil. The cores rested in the oil for 2 h and the porosity could then be calculated from the weight difference, bulk volume, and oil density. Thereafter, the following procedures were used prior to the imbibition tests at 408C. 2.3.1.1. Procedure 1. The cores were aged in a closed container filled with oil for 4 days at 508C. The volume ratio between the core and the oil was about 2 during the aging process. 2.3.1.2. Procedure 2. The cores were placed in Hassler core holders, flooded with at least 1 PV of oil in each direction, with a confining pressure not exceeding 33 bar, and finally aged for 4 days at 508C in a closed container surrounded with oil of the same volume ratio as described in Procedure 1.
Table 4 Experimental data for the different imbibition systems Test
Oil
Saturation procedure
Core a height, diameter Žcm.
1 2 3 4 5 6 7 8 9
A A B B B C D E F
1 1 1 1 3 2 3 3 3
2.72, 3.80 3.20, 3.80 5.00, 3.70 5.10, 3.80 5.64, 3.80 5.48, 3.83 5.58, 3.84 6.70, 3.82 5.85, 3.83
a
Before removing the outer layer. After removing the outer layer.
b
Core b height, diameter Žcm.
5.00, 3.46 4.74, 3.46 5.97, 3.45 5.38, 3.52
Porosity f Ž%.
PV Žcm3 .
53.3 53.8 49 48 50.5 47.7 43.5 45.8 44.9
16.43 19.53 26.40 27.72 23.74 21.26 28.11 25.56 23.51
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
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Table 5 Experimental data for the system with initial water saturation Test
Oil
Saturation procedure
Core a height, diameter Žcm.
Core b height, diameter Žcm.
Porosity Ž%.
S wi Ž%.
PV Žcm3 .
HCPV Žcm3 .
10
F
4
5.71, 3.83
5.05, 3.46
46.4
23.0
22.032
16.965
a
Before removing the outer layer. After removing the outer layer.
b
2.3.1.3. Procedure 3. Similar to Procedure 2, but in addition, the outermost layer Ž2 mm. of the core was removed by shaving off the cores in a lathe just before the imbibition tests. 2.3.2. Irreducible water saturation 2.3.2.1. Procedure 4. The cylindrical core was dried at 908C to constant weight and placed in a container, evacuated, and surrounded with brine. The material rested in the brine for 2 h and the porosity was then calculated from the weight difference, bulk volume, and brine density. The core was then placed in a Hassler core holder and flooded with at least 1 PV of oil in each direction, with a confining pressure not exceeding 25 bar. The porous medium was aged for 1 month at 908C in a closed container surrounded with oil, with the same ratio between core volume and oil volume as in Procedure 1. The outermost layer Ž2 mm. of the core was removed by shaving off the core in a lathe just ahead of the imbibition test. 2.4. Imbibition experiments The imbibition experiments were conducted in standard Amott cells at 408C. The oil-saturated cores were placed in a vertical position and surrounded by 350 cm3 of brine. The volume of oil produced was measured as a function of time.
tive or relative assessment of the wettability state of similar core material can be obtained by comparing the spontaneous imbibition rate of water ŽJadhunandan and Morrow, 1991; Graue et al., 1998.. In general, the imbibition rate decreases as the degree of oil wettability increases. This procedure, which requires a homogeneous wettability state of the core, was used in this paper to classify the relative wettability state of the different systems. As far as the the scope of the present paper is to work out a technique to obtain homogeneously wetted chalk cores, the reported imbibition results have not been further analysed in terms of dimensionless time for scaling the imbibition ŽMa et al., 1997.. The chemical properties of the functional groups of the surface active material in the crude oil Žespecially asphaltenes and resins. are crucial with regard to the ability to adsorb onto the chalk material. Compared to sandstone, the chalk is much more homogeneous in mineral composition, and therefore, the wetting state of the porous material should be more uniform. The high-molecular-weight polar components will, depending on rock type, initial water saturation, crude oil type, aging temperature and time, alter the wetting properties of the mineral surface towards a more oil-wet state ŽAnderson, 1986; Buckley, 1996; Cuiec, 1984; Denekas et al., 1959; Graue et al., 1994, 1998; Jadhunandan and Morrow, 1991; Milter, 1996; Zhou et al., 1995.. 3.1. 100% oil-saturated chalk
3. Results and discussion Unfortunately, no universal method exists to determine the wettability state of porous media. The most common method to obtain quantitative information is to perform an Amott test, and calculate the Amott–Harvey index ŽAnderson, 1986.. A qualita-
The repeatability of the imbibition was tested by using a water-wet system, i.e. n-heptane as the oil phase, as shown in Fig. 1. The cores were saturated according to Procedure 1. As shown in the figure, the oil production curves were quite reproducible for the two core samples, confirming good repeatability.
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
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Fig. 1. Spontaneous imbibition of brine into chalk cores containing 100% n-heptane Žoil A. at 268C.
It is also indicated from the experiments that the core material appeared to be homogeneous and initially water wet. 3.1.1. Homogeneous wettability Using oil B, i.e. the Ekofisk stock tank oil, and treating the cores according to Procedure 1 Žno flooding of the core., the imbibition profiles for two different cores are shown in Fig. 2. There was no oil expulsion during the first 600 min. The oil production that was initiated after f 600 min took place at a very slow rate, but later on Žafter 1600 min f 1 day., the production rate increased strongly and maximum oil recovery of approximately 74% was achieved within 1.5 weeks. It was observed that the oil was displaced equally from the total surface of the core, indicating a countercurrent flow between the imbibed and displaced fluids governed by capillary forces. The accelerating oil recovery may indicate the existence of a wettability gradient from nearly oil wet at the surface to water wet towards the centre of the core. This assumption was confirmed when cleaving the core after the experiment. The gradient in the colour, which is related to the residual oil and ad-
sorbed surface active material, showed a significant change from dark to light when moving from the boundary of the core towards the centre, as seen in Fig. 3. It must be noticed that porosity calculations based on weight differences clearly verified that the cores were initially totally saturated with the oil.
Fig. 2. Spontaneous imbibition of brine into cores saturated with oil B and treated according to Procedure 1.
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D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
Fig. 3. Picture of the cleaved core Žtest 3. after finishing the spontaneous imbibition process.
Thus, it seems likely that the oil undergoes a chromatographic separation of coloured surface active components as the oil flows into the chalk material during the saturation procedure. The adsorption of surface active components must be very fast, and the oil reaching the central parts of the core is more or less depleted in these components. The result is a wettability gradient inside the core from nearly oil wet at the surface to more water wet in the centre. Two more experiments were carried out to further confirm this hypothesis. In the first experiment, a core saturated with oil F, and treated according to Procedure 1, was cleaved directly after the saturation process was finished, i.e. prior to any imbibition test. As shown in Fig. 4, a colourless fluid is present in the central parts of the core, confirming the existence of a chromatographic separation of coloured surface active material in the oil. In the second experiment, oil B was allowed to pass through a thin glass pipette packed with chalk powder. The first oil drops leaving the capillary of the pipette was colourless, i.e. free from the heavy end fraction of the crude oil. From the present observations, it is very difficult to obtain uniform wettability in the chalk material by just treating the core material according to Procedure 1. In order to obtain a uniform compositional distribution of oil components in the core material, the cores were placed in Hassler core holders and flooded with at least 1.0 PV of oil in each direction, as given
in Procedure 2. It is difficult to do a viscous flooding of fluid through low-permeable chalk with very high porosity Žnearly 50%.. A rather low confining pressure must be applied in order to avoid cracking of the core material. During the aging process, the core is surrounded by fresh crude oil, and a large amount of surface active components from the oil will adsorbrdeposit onto the outermost surface of the core. This may not be representative for the general wetting state for other parts of the core. The wettability induced by the crude oil inside the porous media is restricted by the amount of surface active components residing in the pore volume, because there is limited supply of fresh crude oil here during the aging process. The effect is illustrated in Fig. 5. The core was incised to different depths. The water was imbibed into the cross-sections with the smallest diameter, where the chalk material was most water wet, and the oil was expelled from the dark oil-wet areas, which had been in contact with fresh crude oil during the aging period. It was therefore decided that the outer layer Žabout 2 mm at all surfaces. be removed prior to the imbibition experiments, as in Procedure 3. The result from the imbibition test after the core was treated according to this procedure is shown in Fig. 6. The general feature of the imbibition profile revealed no indication of a wettability gradient inside the core material. This was confirmed when the core was cleaved after the imbibition experiment, as shown in
Fig. 4. Picture showing the compositional gradient of oil F if the core is treated according to Procedure 1, prior to any imbibition test.
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
Fig. 5. Imbibition of water into a core saturated with oil B according to Procedure 2, and cut in different cross-sections.
Fig. 7. The residual oil and adsorbed surface active compounds seemed to be evenly distributed in the core material in sharp contrast to the core, which was treated according to Procedure 1. Thus, in the following experiments, the cores were treated as described in Procedure 3. 3.1.2. Wettability related to oil properties As the present paper is part of a project to study wettability alteration Žoil-wet to water-wet. in chalk
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Fig. 7. Picture showing that residual oil and adsorbed surface active compounds seem to be evenly distributed in the core of the cleaved core at the end of water imbibition.
using surface active chemicals, it is necessary to be able to create homogeneous oil-wet core material within a reasonable time in the laboratory. It is documented in the literature that asphaltenes and resins are the most active fractions of the crude oil concerning wettability alterations of mineral surfaces ŽBuckley, 1996.. However, experimental data so far show no clear correlation between the asphaltener resin content and the crude’s ability to make the mineral surface oil wet, other than the fact that these
Fig. 6. Imbibition profile for a core handled according to Procedure 3.
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materials must be present in the crude oil. Buckley Ž1996. has pointed out four different mechanisms, which can alter an original water-wet surface to an oil-wet state. The most important mechanism in the case of dry surfaces is the polar interaction between acid and base components in the oil and the mineral surface. She noticed that the wettability change caused by this interaction was found to be very fast, and after the modification of the surface, the contact angle was almost constant as a function of time. The rapid rate by which polar components were adsorbed into the chalk surface was also confirmed in our case. Imbibition tests, after treating the cores according to Procedure 3, for the different oils are presented in Fig. 8. The imbibition rates are significantly reduced in comparison with the imbibition profile for the water-wet core, oil A. This confirmed that all crude oils, to varying degrees, have the ability to modify the mineral surface. As can be seen, there is a broad range of rates by which the different cores imbibe the brine spontaneously. The data show, however, that there is a correlation between the acid number ŽAN. and the ability to alter the wetting state of the porous media, as measured by spontaneous imbibition of brine. High AN seems to provoke a stronger
modification of the mineral surface towards more oil wet. This is in line with the suggestions put forward by Buckley Ž1996. that polar interactions are the most important mechanism for wettability change in the absence of initial water in the porous media. It is quite evident from the figure that oil F, which has the highest AN Ž1.73 mg KOHrg., appeared to give the most oil-wetted state, i.e. no imbibition of water was detected even after 33 days. No such correlation exists between the imbibition rates and the content of asphaltenes for the different crude oils. Note that oil D, which has an asphaltene content of about 2.6 wt.%, imbibes water quite well. In this case, the asphaltenic material contains a small number of acid groups ŽAN s 0.055 mg KOHrg., and it has a low adsorption potential towards the chalk surface. Very often, a positive correlation between the AN and the amount of asphaltenes is observed for different oils, but the functional acid groups need not be part of the asphaltene fraction ŽSkauge et al., 1999.. Likewise, in our case, we have an oil with relatively high asphaltenic content and a relatively low AN. The AN and the content of asphaltenes for oils E and C are comparable, 0.41 mg KOHrg, 0.19 wt.% and 0.52 mg KOHrg and 0.33 wt.%, respectively.
Fig. 8. Spontaneous imbibition of brine into chalk cores saturated with different crude oils according to Procedure 3.
D.C. Standnes, T. Austadr Journal of Petroleum Science and Engineering 28 (2000) 111–121
The difference in the imbibition rate for the two cases is, however, unreasonably large. The core saturated with oil C has a very low imbibition rate and it acts nearly as oil wetted. The wax precipitation temperature for the initial crude oil is as high as 538C, shown in Table 2, and it is reasonable to believe that the reduced ability for brine imbibition can be partly ascribed to some kind of blocking effect due to precipitation of wax material in the porous media. It was noticed that wax precipitated from the actual oil at room temperature. Thus, in further wettability alteration studies by imbibition of surface active material, it is important to work with systems free from precipitated organic material in the porous medium. It is concluded that oil F has the ability to change the wettability of the chalk core from water wet to oil wet. The wax-formation temperature of the initial crude oil is about 25–308C, which excludes wax precipitation during the imbibition tests. The oil is stable, and no sign of any precipitate was observed after long-time storage at room temperature. It is further concluded that the negatively charged carboxyl groups are the most active polar functional groups of the crude oil in adsorbing organic material onto the chalk surface. This is also in line with adsorption studies by Thomas et al. Ž1993., stating that carboxylic acids adsorb most strongly, and essentially irreversibly, onto carbonates.
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difficult to get very low initial water saturation by this method. Nevertheless, we used this last method in this work, and the initial water saturation was calculated to be 23%, as given in Table 4. Fig. 9 shows the imbibition profile for a core saturated with oil F and prepared according to Procedure 4. In contrast to the 100% oil-saturated cores, about 7% of the OOIP was displaced by a fast spontaneous imbibition of water. Later, some oil was displaced from the core, amounting to about 9% of OOIP after 8 weeks. The fast expulsion of oil is not related to thermal expansion of the fluids inside the core due to the experimental technique because this is not observed for the 100% oil-saturated cores. Contrary to the 100% oil-saturated cores, the wettability alteration of the chalk core with initial water saturation of 23% must be somewhat inhomogeneous. The outermost part of the core appears to be more water wet. This can be explained due to end effects related to the saturation procedure used to establish residual water saturation. There may be a gradient in the oil saturation close to the surface of the core, i.e. a decrease in the oil saturation. Consequently, the amount of surface active material in this region will decrease, and the chalk will become more water wet. Eventhough 2 mm of the core material was shaved off, this is probably not enough to create a homogeneously oil-wetted core.
3.2. Initial irreducible brine saturation The centrifuge technique has previously been used by Torsæter Ž1984. and Austad et al. Ž1998. to establish initial or irreducible water saturation in reservoir chalk cores from the Ekofisk formation. The cores must be handled carefully in the centrifuge in order to avoid cracking during the centrifuge process. Initial water saturations in the range 20–25% were obtained in this way. For small cores and low-viscosity fluids, it is also possible to perform coreflooding in Hassler cells, ŽGraue et al., 1994, 1998.. Due to the low confining pressure of 25 bar, the flow rate of the oil to generate S wi must be very low, which will give low viscous forces acting on the water phase. Thus, it will be
Fig. 9. Spontaneous imbibition of brine into chalk material at irreducible brine saturation.
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4. Conclusion The following are some general conclusions. v
v
v
v
The adsorption of surface active components onto a dry chalk surface is a rather fast process. Components from the crude oil undergo chromatographic separation during the saturation, as in Procedure 1. In this case, the cores were placed in a container, evacuated, surrounded with oil, and aged for 4 days at 508C. In order to obtain a homogeneous wetting state in the chalk material, it is recommended to oil-flood the core in each direction and remove the outermost layer after aging the core in the actual crude oil. The method can be used for 100% oil-saturated cores and cores with initial water saturation, taking into account the end effects in the latter case. The wettability induced by the crude oils on chalk surfaces is related to the amount of acidic components in the crude oil, i.e. crude oils with high AN have a greater potential to turn the chalk oil wet. It was also noticed that the amount of asphaltenes in the crude oil is not directly related to the potential for turning the chalk oil wet.
Nomenclature AN Acid number Žmg KOHrg oil. BN Base number Žmg KOHrg oil. HCPV Hydrocarbon pore volume Žcm3 . IFT Interfacial tension ŽmNrm. OOIP Original oil in place PV Pore volume Žcm3 . S wi Initial water saturation Žfraction, %. vol.% Volume percent wt.% Weight percent f Porosity Žfraction, %. m Viscosity ŽcP. r Density Žgrcm3 . s IFT ŽmNrm.
Acknowledgements This study was financed by the Norwegian Research Council ŽNFR.. In addition, the authors wish
to thank Phillips Petroleum and Statoil for providing oil samples, and Dan Olsen, GEUS Copenhagen Denmark, for providing the chalk material. Thanks also to Skule Strand for invaluable support during the experimental work.
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