Water Flooding of Carbonate Reservoirs: Effects of ... - ACS Publications

1606

Energy & Fuels 2007, 21, 1606-1616

Water Flooding of Carbonate Reservoirs: Effects of a Model Base and Natural Crude Oil Bases on Chalk Wettability Tina Puntervold,* Skule Strand, and Tor Austad UniVersity of StaVanger, 4036 StaVanger, Norway ReceiVed December 8, 2006. ReVised Manuscript ReceiVed March 7, 2007

Polar components, especially the carboxylic material in crude oil, are known to have great impact on the wetting conditions of carbonates. The water-wetness decreases as the acid number, AN, of the crude oil increases. The success of enhanced oil recovery by water flooding in fractured carbonates is strongly dependent on the wetting conditions of the formation. The impact on wettability of basic compounds present in crude oil has received much less attention than that of carboxylic material, even though the base number, BN, is usually much higher than the AN. Furthermore, acids and bases present in crude oil will react with each other to form acid-base complexes. In this paper, we have studied the impact of basic components on the wetting properties of chalk by using an oil with a constant AN ) 0.5 mg KOH/g oil and varying the AN/BN ratio in the range of 0.24-4.6. The initial water saturation was varied from 0 to 47%. The relative impact of basic material on the wetting properties was studied by means of spontaneous imbibition. In the first series of experiments, a model base (benzyl amine) was used, and it was observed that the water-wetness decreased as the content of base increased up to about 4 times the concentration of acid. For natural bases present in the crude oil, the effect on the wetting property was the opposite, i.e., the water-wetness increased as the amount of bases increased. The difference in the wetting behavior was discussed in relation to the molecular size of the basic material. It was also confirmed that seawater was able to modify the wetting properties and increase the oil recovery by spontaneous imbibition. Experimentally, it should be noticed that special care must be taken to avoid upconcentration of potential determining ions like SO42-, when using a porous plate to drain the core to Swr with water saturated N2.

Introduction Worldwide, approximately one-half of the petroleum reserves are found in carbonate reservoirs.1 The average oil recovery from carbonate is often less than 30%, leaving an enormous amount of petroleum left in the ground. Thus, the potential for enhanced oil recovery (EOR) in these reservoirs is therefore very high. Water flooding is a widely used EOR method. However, the ability of water flooding to increase the oil recovery is strongly dependent on the wetting properties of the rock. As approximately 90% of the carbonate reservoirs are intermediate to oil-wet,1,2 a wettability alteration is necessary for water flooding to be successful in naturally fractured reservoirs. Originally, chalk reservoirs were water-wet and the chalk surface was in equilibrium with the surrounding brine. Calcium ions (Ca2+) present in the initial brine make the chalk surface positively charged at pH < 9. The positive charge of the chalk surface in the presence of Ca2+ or Mg2+ (magnesium ions) has been confirmed by zeta potential measurements on a milled chalk/NaCl brine suspension.3 When oil invaded the chalk reservoir, the interface between oil and water became negatively charged due to partial dissociation of carboxylic groups * Corresponding author. Phone: +4751832213. Fax: +4751831750. E-mail: [email protected], [email protected]. (1) Treiber, L. E.; Archer, D. L.; Owens, W. W. SPE J. 1972, December, 531-540. (2) Cuiec, L. Rock/Crude-Oil Interactions and Wettability: An Attempt To Understand Their Interrelation. Presented at the 59th Annual Conference and Exhibition, Houston, TX, September 16-19, 1984; paper SPE 13211. (3) Zhang, P.; Austad, T. Colloids Surf. A: Physicochem. Eng. Aspects 2006, 279, 179-187.

(-COOH) present in crude oil, resulting in negatively charged carboxylates (-COO-). The resulting thin water film between the positively charged chalk surface and the negatively charged oil-water interface became unstable due to the negative disjoining pressure, and the oil could contact the chalk surface. The carboxylates in the oil could adsorb onto the chalk surface and hence make the chalk less water-wet.4 It has been found that the degree of water-wetness is dictated by the acid number (AN), a measure of the amount of acidic material in the oil. The higher the acid number, the more carboxylates have the possibility of adsorbing onto the chalk surface and decreasing the water-wetting nature of the rock.5 Millions of years ago, when oil initially invaded the carbonate reservoir rock, the oil probably contained more carboxylic material, i.e., the acid number was probably higher than what is measured today. Studies have shown that decarboxylation of carboxylic material takes place at elevated temperatures, and that this process could be catalyzed by the presence of CaCO3.6 Over geological time, this process will cause a reduction in AN. Thus, the amount and properties of the acidic material found in the crude oil will be different from the acidic material, which was present when the crude oil invaded the carbonate rock. This kind of decomposition has not been reported for the basic material, which means that the ratio of AN to BN of the crude oil will change during geological time. Therefore, as a rule of (4) Thomas, M. M.; Clouse, J. A.; Longo, J. M. Chem. Geol. 1993, 109, 201-213. (5) Standnes, D. C.; Austad, T. J. Pet. Sci. Eng. 2000, 28 (3), 111121. (6) Shimoyama, A.; Johns, W. D. Geochim. Cosmochim. Acta 1972, 36, 87-91.

10.1021/ef060624b CCC: $37.00 © 2007 American Chemical Society Published on Web 04/17/2007

Water Flooding of Carbonate ReserVoirs

Energy & Fuels, Vol. 21, No. 3, 2007 1607

Table 1. Oil Properties

Table 2. AN/BN Ratios of Oils Used

oil

AN (mg KOH/g oil)

BN (mg KOH/g oil)

density (g/cm3)

A B C

1.9 0.20 0.20

0.50 0.10 2.4

0.808 0.801 0.856

thumb, the AN/BN ratio usually decreases as the temperature of the reservoir increases due to the decrease in AN at elevated temperature, as illustrated by the following examples:

Ekofisk: T ) 130 °C; AN ) 0.10 mg KOH/g; BN ) 1.5 mg KOH/g oil; (AN/BN) ) 0.067 Valhall: T ) 90 °C; AN ) 0.20 mg KOH/g; BN ) 2.4 mg KOH/g oil; (AN/BN) ) 0.083 It is known that the wettability of carbonates is very strongly related to the AN of the crude oil.5 It is a general observation for carbonate reservoirs that the water-wetness increases as the reservoir temperature increases.7 Wettability tests by aging chalk cores in crude oils of different AN at different temperatures confirmed that the AN played the major role concerning wetting conditions, while no correlation to the aging temperature was observed, i.e., the temperature appeared to play a minor role.8 The influence of bases on the wetting conditions in carbonates has not been studied in detail. The basic constituents in crude oil are compounds containing a nitrogen (N) atom, i.e., pyridine, quinoline, and their derivates. The basic N atoms are mostly found in molecules of the high boiling fractions, though they exist throughout the total boiling range of the crude oil.9 Acids and bases present in the crude oil normally react with each other by the formation of an acid-base complex. The objective of this work was to investigate the effects of bases on the wettability in a crude oil/brine/chalk system at a constant value of the AN. The first part of the work concerned a model base, benzyl amine, which is not naturally found in crude oil, while the last part of the work concerned the natural bases of petroleum. Experimental Rock Material. Outcrop Stevns Klint chalk taken from the Sigerslev quarry nearby Copenhagen in Denmark was used as the porous medium. This chalk is from the Maastrichtian age, and it is believed to be comparable to the reservoir chalk that is found in the Ekofisk and Valhall fields in the North Sea. It has a fairly high porosity (45-50%), low permeability (2 mD), and a specific surface area of about 2 m2/g.10,11 Oils. Two crude oils were used in these experiments, Heidrun and Valhall. The Heidrun oil was diluted with 40% n-heptane, centrifuged, and filtrated through a 5 µm Millipore filter. No precipitation of asphaltenes was observed during storage. The resulting oil was termed Oil A (AN ∼ 1.9 mg KOH/g oil, BN ∼ 0.50 mg KOH/g oil). Oil A was treated with silica gel to remove surface-active material, centrifuged, and filtrated through a 5 µm Millipore filter, and the resulting oil from this process was termed Oil B (AN ∼ 0.20 mg KOH/g oil, BN ∼ 0.10 mg KOH/g oil). Oil C (AN ∼ 0.20 mg KOH/g oil, BN ∼ 2.4 mg KOH/g oil) was pure Valhall oil that was centrifuged and filtrated through an 8 µm Millipore filter. The oil properties are summarized in Table 1. In (7) Rao, D. N. SPE ReserVoir EVal. Eng. 1999, 2 (5), 420-430. (8) Zhang, P.; Austad, T. The relative effects of acid number and temperature on chalk wetability. Presented at the 2005 SPE International Symposium on Oilfield Chemistry, Houston, TX, February 2-4, 2005; paper SPE 92999. (9) Speight, J. G. The chemistry and technology of petroleum, 2nd ed.; Marcel Dekker: New York, 1991. (10) Frykman, P. Marine Pet. Geol. 2001, 18 (10), 1041-1062. (11) Røgen, B.; Fabricius, I. L. Pet. Geosci. 2002, 8 (3), 287-293.

AN/BN ratio theor 0.25 0.50 1.0 2.0 3.0

AN (mg KOH/g oil)

BN (mg KOH/g oil)

temp (°C)

theora

meas

theora

meas

AN/BN ratio

70 50, 90, 110 70 50, 90, 110 70 50, 90, 110 70 50, 90, 110 70 50, 90, 110

0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50

0.62 0.55 0.48 0.46 0.50 0.46 0.49 0.48 0.43 0.48

2.1 2.1 1.0 1.0 0.52 0.52 0.26 0.26 0.17 0.17

1.9 2.3 1.1 1.1 0.50 0.63 0.22 0.24 0.093 0.17

0.32 0.24 0.45 0.42 1.0 0.74 2.2 2.0 4.6 2.8

a The theoretical value is calculated from mixing ratios of oils A, B, and C with given values of AN and BN.

the experiments using the model base benzyl amine, Oil A and B were mixed in a certain ratio giving an acid number (AN) of 0.50 mg KOH/g oil. The model base, benzyl amine, which is normally not found in crude oil, was then added to this oil in different amounts to give three oils with constant acid numbers but varying base numbers (BN) with AN/BN ratios of 1:1, 1:4, and 1:10. In the natural base experiments, oils A, B, and C were combined in different ratios, which gave five oils with a nearly constant acid number of 0.50 mg KOH/g oil, but varying base numbers. Oils with AN/BN ratios of approximately 0.25, 0.5, 1, 2, and 3 were obtained. Determination of Acid Number and Base Number. A Mettler Toledo DL55 titrator is used in determining acid and base numbers by potentiometric titrations with internal standard. The methods used were developed by Buckley and Fan,12 which are modified variations of ASTM D2896 for base number titration and ASTM D664 for acid number titration. The measured acid and base numbers for the five oil mixtures with natural petroleum bases are given in Table 2. Brines. Ekofisk brine (EF) and Valhall brine (VB) were used to create the initial water saturation. In the model base experiments, synthetic seawater with increasing amount of sulfate (SO42-) was used as the imbibition brine, i.e., seawater without SO42- (SSW/ US), seawater with normal SO42- content (SSW), seawater with twice the normal amount of SO42- (SSW2S), and seawater with four times the normal amount of SO42- (SSW4S). In the natural petroleum base experiments, VB was used instead of SSW/US, followed by SSW and SSW with 1 wt % C12TAB surfactant. For the chromatographic wettability method, two brines were used, SSW-U and SSW-M. The latter contains both sulfate and thiocyanate (SCN-), while the first contains neither of the two components. The brine compositions can be viewed in Table 3. Core Preparation. Two big chalk blocks were used: one for the model base experiment series and another for the natural petroleum base experiment series. Core preparation was based on the procedure developed by Standnes and Austad.5 The cylindrical cores were drilled out from the block by an oversized bit, shaved in a lathe to a diameter of ∼38 mm and cut to a length of ∼65 mm. The cores were dried at 120 °C to a constant weight. Further core preparation varied with the type of initial fluid saturation. • 100% Oil Saturation (Swi ∼ 0%). The dry core was saturated with oil under vacuum, placed in a Hassler core holder at room temperature, and flooded with oil (1.5 pore volume (PV) at rate 1 mL/min) in each direction. Due to the weak chalk, the confining pressure did not exceed 25 bar. After flooding, the core was immersed in the oil inside a sealed steel container and aged at 50 °C for 5 days. • High Initial Water Saturation (Swi ∼ 30-50%). The dry core was saturated with initial brine (EF) under vacuum, placed in a Hassler core holder at room temperature (20 °C), and flooded with (12) Fan, T.; Buckley, J. Acid number measurements revisited. Presented at the 2006 SPE IOR Symposium, Tulsa, OK, April 22-26, 2006; paper SPE 99884.

1608 Energy & Fuels, Vol. 21, No. 3, 2007

PunterVold et al. Table 3. Molar (mol/L) Composition of Brines

EF

VB

SSW/US

SSW

SSW2S

SSW4S

SSW-U

SSW-M

VB/US

1.196

0.009 1.065 0.001

0.002 0.597

0.002 0.525 0.024

0.002 0.453 0.048

0.002 0.309 0.096

0.002 0.623

0.009 1.066

0.008 0.029 0.996 0.005 1.112 62.8

0.045 0.013 0.474 0.010 0.657 34.2

0.045 0.013 0.450 0.010 0.657 33.4

0.045 0.013 0.426 0.010 0.657 32.6

0.045 0.013 0.378 0.010 0.657 31.0

0.045 0.013 0.500 0.010 0.683 35.7

0.002 0.525 0.024 0.024 0.045 0.013 0.450 0.034 0.681 35.7

-

HCO3 ClSO42SCNMg2+ Ca2+ Na+ K+ ionic strength TDS (g/L)

0.025 0.231 0.684 1.452 68.0

oil (1.5 PV at rate 1 mL/min) in each direction to obtain initial water saturation. The confining pressure did not exceed 25 bar. After flooding, the core was immersed in oil inside a sealed steel container and aged at 90 °C for 4 weeks. • Low Initial Water Saturation (Swi ∼ 10%). The dry core was first saturated with initial brine (VB) under vacuum. Then, it was placed on a porous plate inside a pressurized container and drained with water saturated nitrogen gas in pressure steps from 2.5-10 bar at room temperature until a brine saturation of about 10% was obtained. After drainage, the core was placed in a Hassler core holder at 90 °C and flooded with 1.5 PV of oil at a rate 1 mL/min in each direction using a backpressure of 6-10 bar. Again, the confining pressure did not exceed 25 bar. After flooding, the core was immersed in oil inside a sealed steel container and aged at 90 °C for 4 weeks. After the aging period, the cores were shaved 2 mm on all sides to remove any unrepresentative adsorbed organic material at the chalk surface. Imbibition. After the cores were shaved, they were placed in Amott cells for imbibition studies at low temperatures (50 and 70 °C), and in sealed steel containers when imbibed at high temperatures (90 and 110 °C). The cells were filled with the actual imbibing brine, and the amount of oil produced (% OOIP) was recorded with time on a graded scale. New Chromatographic Wettability Test Method. This test method was developed by Strand et al.,13 and it is based on chromatographic separation between sulfate and a tracer, thiocyanate. After flooding the core with oil, 1.5 PV in each direction, the core was wrapped in Teflon tape leaving only the ends open. The core was then aged in oil inside a steel container for 4 weeks. After aging, the core was shaved 1-2 mm at the ends to remove any unrepresentative adsorbed organic material. The core was placed inside the Hassler core holder again, with a confining pressure not exceeding 25 bar, and flooded with 1.0 PV SSW-U brine at a rate of 0.2 mL/min. This brine contained no sulfate nor tracer as listed Table 3. This flooding period was followed by another one of 1.0 PV at rate 0.4 mL/min using the same brine. At this point, Sor could be determined from the amount of displaced oil. Next, the core was flooded with at least 2.0 PV at a rate of 0.2 mL/min with brine SSW-M, which contained sulfate and tracer. The effluent was collected in fractions of 1-3 mL by use of a fraction collector. The fractions were analyzed for concentrations of sulfate and thiocyanate, and the concentration relative to the initial concentration was plotted against injected PV. The gap between the tracer curve, thiocyanate, and the sulfate curve is directly proportional to the pore surface available for adsorption by sulfate, which corresponded to the water-wet surface. Thiocyanate, being a watersoluble tracer, does not adsorb to the chalk surface and will therefore exit the core ahead of sulfate. A wetting index (WINew) describing the fraction of water-wet area was calculated according to the following equation: WINew )

AWett AHeptane

(1)

(13) Strand, S.; Standnes, D. C.; Austad, T. J. Pet. Sci. Eng. 2006, 52, 187-197.

0.008 0.029 0.996 0.005 1.112 62.8

Where, AWett and AHeptane are the areas between the SCN- and the SO42- curve for a complete water-wet system using heptane as oil and the actual crude oil system, respectively. All areas were calculated using the trapezoidal rule. According to the definition of WINew: WINew ) 1.0

represents a completely water-wet system

WINew ) 0.5

represents an intermediate wet system

WINew ) 0.0

represents a completely oil-wet system

Results and Discussion Previously, work has been done to investigate the impact of acid number on wettability and oil recovery from chalk.5,8 It was seen that the water-wetness and oil recovery by spontaneous imbibition decreased as the AN increased up to a certain limit. No systematic studies on the impact of BN on chalk wettability have, however, been performed. As many crude oils in carbonates contain a high base number, i.e., Valhall oil with BN ∼ 2.4 mg KOH/g oil, it is of great interest and importance to investigate the possible impact of base number on the wetting conditions as well. Enhanced oil recovery by spontaneous imbibition is observed when using seawater due to wettability modification toward more water-wet conditions. It was documented that SO42- was the key parameter in the chemical mechanism for the wettability modification.3,14,15 Thus, the extent of oil recovery by spontaneous imbibition of seawater without SO42- present (SSW/US) will give information about the relative initial wetting condition of the cores saturated with oils with different BNs and constant ANs, because no wettability modification will take place during the imbibing process. Model Base: Benzyl Amine. Benzyl amine is a primary amine not normally present in crude oils. Compared to pyridinelike bases, which are very common in crude oil, benzyl amine is a much stronger base as documented by the pKa values for benzyl amine and pyridine: 9.33 and 5.25, respectively. Thus, the chosen model base represents a rather strong base compared to the basic material normally found in petroleum. Benzyl amine is also a very small base molecule compared to most of the nitrogen containing bases, which are mostly present in the heavy end fraction, i.e., resins and asphaltenes. Different amounts of benzyl amine were added to the oil with AN ∼ 0.50 mg KOH/g oil. This gave four different oils with identical ANs but with different BNs. The oils have been given the names AN/BN 1:0, 1:1, 1:4, and 1:10. Chalk cores were saturated with these oils, and spontaneous imbibition experiments were performed at 70 °C. The initial water saturation, EF brine, varied between high (Swi ∼ 30-50%), low (Swi (14) Zhang, P.; Tweheyo, M. T.; Austad, T. Colloids Surf. A: Physicochem. Eng. Aspects 2006, in press. (15) Zhang, P.; Tweheyo, M. T.; Austad, T. Energy Fuels 2006, in press.



∼ 10-20%), and nearly zero (Swi ∼ 0%). Core properties are given in Table 4. High Swi (∼30-50%). The oil recovery versus time plot is presented in Figure 1. The first imbibition sequence using SSW without SO42- (SSW/US) will indicate the relative initial wetting conditions for the different cores. The wettability modification during the imbibing process is negligible due to the absence of SO42-.14 The fact that the oil recovery decreases as the content of the base increases for the oils with AN/BN ratios of 1:0, 1:1, and 1:4 confirms that the water-wet nature of the chalk core decreases as the content of base increases. As the AN/BN ratio decreased beyond 1:4, the effect of benzyl amine on the wetting condition appeared to be small, i.e., the oil recovery profiles for the two cores saturated with oils with AN/BN ratios similar to 1:4 and 1:10 were almost identical. The oil recovery from the core without added base is about twice the amount of oil recovered from the cores saturated with oils with BNs 4-10 times higher than the initial AN. Thus, the model base must be an active component in the wetting mechanism in such a way as to increase the organic coating of the chalk surface. It is, however, interesting to note that ordinary seawater, SSW, still has the potential to modify the wetting condition. For all the wetting conditions, a change in imbibing fluid from SSW without SO42- to ordinary SSW increased the oil recovery. The increase in oil recovery was highest for the cores of lowest water-wetness. Except for the core containing oil with an AN/ BN ratio similar to 1:4, the oil recovery plateau reached about 45%. By a subsequent increase in the content of SO42- in the imbibing fluid, 2 and 4 times the concentration present in SSW, respectively, the oil recovery increased to nearly 55% after 100 days. Low Swi (∼10%). In these experiments, the low initial water saturation with EF-brine was generated using a porous plate and water saturated nitrogen gas to drain the cores. As expected, the cores became less water-wet during the aging period due to the decrease in Swi. This is documented by the plateau recovery when using SSW/US as the imbibing fluid, Figure 2, and these results agree with previous studies.16 At low water saturation, the amount of surface-active material in the crude oil increases due to higher oil saturation, and low water saturation also makes the water film on the chalk surface thinner so that oil can adsorb more easily on the chalk surface. However, as for the high Swi results in Figure 1, the same general trend regarding wettability was observed at low Swi, i.e. the water-wetness decreased as the base content increased. Also in this case, the cores saturated with oils with AN/BN ratios 1:4 and 1:10 appeared to show similar wetting conditions, which confirms that the decrease in water-wetness levels off as the BN increases beyond 4 times the AN. The positive impact of SO42- in the imbibing fluid is also confirmed by the jump in oil production by using SSW, SSW2S, and SSW4S as imbibing fluids, Figure 2. Note that the

imbibition rate is lower than for the cores with high Swi in Figure 1, and that the oil recovery only reached about 40-50% when the tests were abandoned after 225 days. Without Initial Water (Swi ∼ 0%). The imbibition rate without any sulfate present in the imbibing fluid was very low, but the final plateau recovery was higher than in the previous experiments with initial water present, Figure 3. In these experiments, the impact of model base in the crude oil regarding wetting properties was not as obvious as for the experiments with initial water present. There is a decrease in water-wetness as the AN/ BN ratio is varied from 1:0 to 1:1 when using SSW/US as the imbibing fluid. The oil recoveries from the cores saturated with oils having AN/BN ratios of 1:1 and 1:4 appeared to be similar. When the BN was increased to 10 times the AN, the wetting conditions appeared to be similar to the core without any added model base. The only statement that can be made from these tests is that the impact of added model base appeared to be different from the cores containing initial water. The difference could possibly be linked to the fact that benzyl amine and the benzyl ammonium ion are partly soluble in water, which may facilitate contact to the chalk surface in the presence of water. Natural Petroleum Bases. Benzyl amine is a model base that is not found in crude oil and can therefore not represent the real petroleum bases. To investigate the effects of real bases in crude oil on the wetting properties of chalk, the oil recovery by spontaneous imbibition into cores containing four to five different oils with a nearly constant AN, AN ∼ 0.50 mg KOH/g oil, and varying BNs was performed. The oils were made by mixing oil A, B, and C (see experimental part), and the AN/ BN ratios obtained were in the range of 0.24-4.6. In these oils, all the basic constituents are naturally found in petroleum. In all cases, the cores were saturated with VB and drained by means of a porous plate and water saturated nitrogen gas to Swi in the range of 10%. The cores were saturated with the respective oils and aged in the actual oil at 90 °C for 4 weeks as described earlier. The motivation for these experiments was the following: (1) To test the impact of natural bases in crude oil on the wetting properties of chalk. (2) To test the ability of SSW and SSW with added SO42- to create a wettability modification to increase the oil recovery by spontaneous imbibition at different temperatures. (3) To test the cationic surfactant, C12-N(CH3)3Br, C12TAB, as a wettability modifier for crude oils containing different AN/ BN ratios.17 In order to compare the wettability data with the results obtained using the model base, the imbibition tests were first performed at 70 °C (Figure 4). Compared to a great number of previous studies using crude oil with AN ) 0.50 mg KOH/g oil, these cores appeared surprisingly very water-wet as seen by the high oil recovery when using VB with very low content of SO42- as the imbibing fluid. Another important observation was that the water-wetness appeared to decrease as the AN/BN ratio increased, which is opposite to the observation for the small model base molecule, benzyl amine. The oil recovery was very fast, and after approximately 5 days, the imbibing fluid was changed to SSW without reaching the oil recovery plateau. Even though the oil recovery was high at first, it increased further using SSW. The oil recovery for the two cores with the lowest AN/BN ratios, 0.32 and 0.45, was exceptionally high, about 70%, while the recovery from the two cores with highest AN/ BN ratios, 2.2 and 4.6, was significantly lower, slightly below 60%. When changing the imbibing brine in the latter two cores

(16) Jadhunandan, P. P.; Morrow, N. R. In Situ: Oil-Coal-Shale-Minerals 1991, 15 (4), 319-345.

(17) Standnes, D. C.; Austad, T. J. Pet. Sci. Eng. 2000, 28 (3), 123143.

Table 4. Core Properties for Benzyl Amine Experiments test

oil AN:BN

Swi (%)

high Swi

1:0 1:1 1:4 1:10 1:0 1:1 1:4 1:10

47 30 37 36 10 12 11 19

low Swi


PunterVold et al.

Figure 1. Spontaneous imbibition experiments with model base at 70 °C showing oil recovery as a function of time for chalk cores saturated with different AN/BN ratio oils, high Swi ∼ 30-50%, and EF-brine.

Figure 2. Spontaneous imbibition experiments with model base at 70 °C showing oil recovery as a function of time for chalk cores saturated with different AN/BN ratio oils, low Swi ∼ 10-20%, and EF-brine.

to SSW with 1.0 wt % C12TAB, the oil recovery increased to about 75% for both cores. Thus, the cationic surfactant was still able to improve the oil recovery by spontaneous imbibition as observed previously for oils with high AN/BN ratios.17 Normally, the imbibition rate decreases as the temperature decreases,3,18 but spontaneous imbibition studies at 50 °C (Figure 5) did not discriminate between the imbibition curves at different AN/BN ratios significantly better than that observed at 70 °C. The same trend in the imbibition efficiency was, however, observed. By suggesting that the imbibition rate and the amount of oil recovered are linked to the wetting conditions, the presence of natural bases appeared to improve the water-wetting nature of the chalk. Due to the high oil recovery obtained by using VB, the change of imbibing fluid to SSW and SSW2S did not improve the oil recovery very much. Thus, the effect of SO42-, present in the imbibing fluid on the oil recovery, is not obvious from these data. Oil C with a low AN and high BN, 0.20 and 2.4 mg KOH/g oil, respectively, was significantly more viscous than oil A and (18) Høgnesen, E. J.; Strand, S.; Austad, T. Presented at the 14th Europec Biennial Conference, Madrid, Spain, June 13-16, 2005; paper SPE 94166.

B. Thus, low AN/BN ratio oils, which contained relative large amounts of oil C, were more viscous than the other oil mixtures used, as shown in Figure 6. The viscosities of oils with AN/ BN ratios of 0.74 and 2.8 were quite similar but lower than the value of the oil with an AN/BN ratio of 0.25. The viscosity difference decreased as the temperature increased. If the difference in the observed imbibition rate was dictated by the differences in oil viscosity, then the oils with low values of the AN/BN ratio should have the lowest imbibition rate. The opposite is, however, the case, i.e., the cores containing the most viscous oils showed the strongest imbibition. Thus, the difference in spontaneous imbibition must mainly be dictated by different wetting conditions of the cores and not by the viscosity of the oil. Imbibition tests at 90 and 110 °C did not discriminate between the various AN/BN ratios of the crude oil used (Figures 7 and 8, respectively). The cores appeared to be too water-wet, and the oil recovery plateau of 60-70% was reached very fast, i.e., in less than 1 day. Core Preparation. On the basis of our previous experience, the cores prepared from the chalk block used in the natural base



Figure 3. Spontaneous imbibition experiments with model base at 70 °C showing oil recovery as a function of time for chalk cores saturated with different AN/BN ratio oils with Swi ∼ 0%.

Figure 4. Spontaneous imbibition experiments with petroleum bases at 70 °C showing oil recovery as a function of time for chalk cores saturated with different AN/BN ratio oils, Swi ∼ 10%, and VB.

experiments appeared to be more water-wet than previous chalk material used in the presence of crude oil with AN ∼ 0.50 mg KOH/g oil.19,20 The high water-wetting nature of the cores was also confirmed by the newly developed wettability test based on chromatographic separation between the nonadsorbing tracer SCN- and SO42-.13 The wetting indices were measured at room temperature on three different aged cores saturated with oils having AN/BN ratios of 0.24, 0.74, and 2.8. In Figure 9, the separation curves between the tracer, SCN-, and SO42- for the three cores are shown. The area between the two corresponding curves is directly proportional to the water-wet area of the core. (19) Austad, T.; Strand, S.; Høgnesen, E. J.; Zhang, P. Seawater as IOR fluid in fractured chalk. Presented at the 2005 SPE International Symposium on Oilfield Chemistry, Houston, TX, 2005; paper SPE93000. (20) Zhang, P.; Austad, T. Waterflooding in chalk: Relationship between oil recovery, new wetability index, brine composition and cationic wetability modifier. Presented at the 14th Europec Biennial Conference, Madrid, Spain, June 13-16, 2005; paper SPE 94209.

The wetting index (WINew), representing the water-wet fraction of the surface area, is determined as the ratio between the area for the actual sample and the area obtained for a completely water-wet system using heptane as the oil phase. On the basis of the separation area between the two corresponding curves, the wetting index (WINew) was calculated for each core: WINew ) 0.87, 0.81, and 0.83 for the cores with AN/BN ratios of 0.24, 0.74, and 2.8, respectively. These values confirmed the results from the imbibition tests that the cores were almost completely water-wet, and it is therefore difficult to discriminate between the wetting properties using this technique. In previous experiments,5,8,21 the procedure for preparing the cores was as follows: (1) The cores drilled from the block were dried at 90 °C until a constant weight. (21) Strand, S.; Høgnesen, E. J.; Austad, T. Colloids Surf. A: Physicochem. Eng. Aspects 2006, 275, 1-10.


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Figure 6. Oil viscosities at different temperatures.

(2) The cores were evacuated and saturated with the initial brine. (3) Swi (25-40%) was established by flooding the cores with 1.5-2.0 PV of oil in each direction. (4) Thereafter, the cores were aged in the actual crude oil at 90 °C for 4 weeks. (5) Finally, the cores were shaved by about 2 mm prior to imbibition studies. It has been documented by several studies that SO42- in combination with Ca2+ and Mg2+ is able to increase the waterwetting nature of chalk, especially at high temperatures.3,14,15 Remember that the cores were aged at 90 °C for 4 weeks. Therefore, there may be at least 2 reasons why the cores appeared so water-wet: (1) The new chalk block may contain increased contamination of SO42-. (2) The cores were drained to a Swi value of about 10%, which was much lower than the value previously obtained by oil flooding (Swi 25-40%). Due to adsorption of SO42- onto the

chalk surface, the apparent concentration of SO42- in the residual water can increase. It was decided to investigate these possibilities. Two dried cores were flooded with distilled water, and the content of SO42in the effluent was determined as illustrated in Figure 10. The average amount of SO42- eluted from the cores after flooding 4.1 PV was calculated to approximately 5.0 mg SO42-. The average PV was 34 mL. Then, 15 cores of similar size and saturated with VB/US were drained using a porous plate and water saturated N2. The total amount of SO42- present in the drained volume of water was recalculated in terms of the amount of SO42- leaving each core as a function of depleted PV. This is illustrated in Figure 11 where, for comparison, the SO42- concentration of the effluent during flooding is also included for one of the two cores. On average, 2.2 mg SO42- was eluted from a core with a PV of 34 mL. Thus, 2.8 mg SO42- still remain in the core after reaching a residual water saturation of ∼10%. The apparent concentration of SO42- in the residual water then corresponded to about 0.70





g/L, which is close to one-third of the concentration present in SSW. Thus, during aging at 90 °C, the amount of SO42- initially present in the pore space and the amount of Ca2+ present in the VB is probably sufficient to reduce the adsorption of carboxylic material onto the chalk surface. This is in line with previous observations regarding wettability modification.15,21 A lesson learned from the present experiments is that outcrop cores must be flooded with distilled water to remove SO42- or other potential determining ions from the pore space prior to drying in order to be able to create reproducible wetting conditions for chalk. This is especially important if the initial brine contains potential determining ions toward the rock surface at low initial concentration, like SO42-. Effects of Temperature. The key components in seawater responsible for the wettability modification are SO42-, Ca2+, and Mg2+, and the chemical mechanism behind this modification has been studied and presented in the work of Zhang et al.14 Wettability modification is initiated by adsorption of SO42- onto the positively charged chalk surface causing a decrease in the

positive surface charge. Due to the decrease in electrostatic repulsion, more Ca2+ from seawater will have access to the chalk surface and will be able to react with the adsorbed carboxylic groups and release some of them from the surface. At high temperatures, >90 °C, Mg2+ can substitute Ca2+ on the chalk surface, and it was suggested that Mg2+ also could displace the Ca2+-carboxylic group complex from the surface.14 It was experimentally verified that neither SO42- nor Ca2+ or Mg2+ were able to promote significant wettability modification when they were acting alone. The affinity of SO42- toward the chalk surface increases with temperature, and the increase is more pronounced as the temperature is increased beyond 100 °C, probably due to dehydration of SO42- caused by the breakage of hydrogen bonds.21 Thus, an increase in the adsorption of SO42- will also increase the affinity of Ca2+ and Mg2+ toward the chalk surface, which will result in increased water-wetness. When cores were prepared by the porous plate technique, the small initial concentration of SO42- was up-concentrated to a level that had


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Figure 9. Chromatographic wettability test on chalk cores saturated with oils containing petroleum bases at digfferent AN/BN ratios.

Figure 10. Sulfate content in effluent fractions from initial cores (PV ∼ 34 mL) flooded with distilled water at 50 °C.

Figure 11. Sulfate content in effluent fractions from 15 cores (PV ∼ 34 mL) saturated with VB/US and drained with a porous plate.

impact on the wetting conditions. The wetting state obtained when aging the cores at 90 °C may change if the cores are put into imbibition cells at different temperatures due to the presence of all the active ions in the pores. Therefore, spontaneous

imbibition using VB/US increased as the temperature increased (Figures 4-7) mostly due to an increase in water-wetness. Wetting Mechanism. The fact that the addition of a small model base, benzyl amine, to an acidic crude oil (AN ) 0.50



Figure 12. Effect of aging time on oil recovery at 50 °C with an AN/BN of 2.0.

mg KOH/g oil) had an opposite effect on the wetting behavior compared to natural bases present in crude oil suggests that the wetting mechanism is different for the two cases. Because the concentration of potential determining cations (Ca2+ and Mg2+) is much higher than the concentration of potential determining anions (SO42-) in the initial brine, the chalk surface is positively charged.14,15 The small model base is a primary amine, a relatively strong base, and it is not originally present in crude oil. Benzyl amine will react with carboxylic acids in the crude oil according to the following chemical reaction:

PhsCH2sNH2 + RsCOOHdPhsCH2sNH3+ + RsCOOThe small cationic benzyl ammonium ion, which is soluble in the aqueous phase, appears to coadsorb onto the chalk surface together with the large anionic carboxylate. Thus, benzyl amine can enhance the adsorption of large carboxylic molecules by coadsorption onto the chalk surface. Coadsorption can be facilitated due to little steric hindrance and strong electrostatic interaction between the two oppositely charged species. Furthermore, the electrostatic repulsion between negatively charged carboxylates at the chalk surface is decreased by the coadsorption of the cationic benzyl ammonium ion. The natural nitrogen-containing bases are linked mostly to the heavy end fraction of crude oil, i.e., they are very large molecules.9 The adsorption of organic material onto the chalk surface appeared to decrease as the amount of natural bases increased when the AN was constant, AN ∼ 0.50 mg KOH/g oil. Thus, it appears that the natural bases react with carboxylic material in the crude oil and form acid-base complexes in chemical equilibrium with the acidic and basic material. The complex has a very large molecular weight, and it is very little soluble in the aqueous phase. Furthermore, due to steric hindrance close to the positively charged N-atom, the coadsorption of natural bases together with carboxylic material is limited. Thus, it seems like the natural bases delay adsorption or partly prevent the carboxylic material from adsorbing onto the positively charged chalk surface. A relevant question to be asked is the following: “If the effect of natural bases on the wetting condition is just a kinetic effect, i.e., to slow down the adsorption rate of carboxylic material, is then an aging period

of 4 weeks at 90 °C sufficient to arrive close enough to equilibrium?” The effect of aging time on the spontaneous imbibition of SSW/US was therefore tested. Three cores with a low initial water saturation of ∼15% were flooded with the same oil with an AN/BN ratio of 2.0, but they were aged for different periods of time, i.e., 2, 4, and 8 weeks at 90 °C. After the aging period, they were prepared for spontaneous imbibition at 50 °C. The results from these experiments are given in Figure 12. Although there is not much difference between the three cores, there is a trend pointing toward a less water-wet state after a longer aging period. The difference between 2 weeks of aging time and 8 weeks is less than 10% OOIP. Therefore, it appears that the decreased adsorption of organic matter onto the chalk surface in the presence of natural bases is not due to a kinetic process, but rather a permanent improved solubilization of surface-active material in the crude oil. Practical Implications. It is important to note that the relative amounts of acids and bases initially present in the crude oil, which invaded a carbonate reservoir millions of years ago, may be completely different from the values determined today. Carboxylic components in the crude oil are lost due to adsorption onto the chalk surface and thermal decomposition (decarboxylation), which is catalyzed by CaCO3.6 It is documented in this work that the water-wetness decreases as the amount of natural crude oil bases increases up to a certain ratio. Thus, one cannot expect to mimic the reservoir wettability condition by just aging the outcrop chalk cores at a low initial water saturation in the actual reservoir oil. It is therefore suggested to prepare the core with a crude oil with an AN/BN ratio that gives the correct wetting state when aged at the actual reservoir temperature. Afterward, the oil used can be displaced by the actual reservoir crude oil. It is also important, prior to the porous plate drainage, that the outcrop core is flooded with at least 4 PV of formation brine free from SO42- to be sure that up-concentration of SO42does not take place. Conclusions (1) The model base, benzyl amine, which is a fairly strong base and a small molecule compared to the natural petroleum bases, is able to affect the chalk wettability in such a way as to


decrease the water-wetness as the concentration of base increases. This is believed to be due to coadsorption of positively charged benzyl amine with the carboxylic groups onto the chalk surface. The electrostatic repulsive forces are reduced, enabling more carboxylic material to adsorb resulting in less water-wet chalk. (2) Natural petroleum bases, that are large molecules, behave in a different manner. As the amount of base is increased the degree of water-wetness increases. Due to steric hindrance, these molecules are probably not able to coadsorb with the carboxylates onto the chalk surface. Instead, they seem to be forming acid-base complexes with the carboxylates in the oil phase, thereby preventing the carboxylates from adsorbing. (3) The sulfate in seawater seems to be able to alter wettability toward a more water-wet condition even in the cases where a large amount of bases is present in the crude oil. The effect could be seen both with the model base and natural petroleum bases present, but it is more obvious as the temperature increases due to the increased affinity of sulfate to the chalk surface. (4) The cationic surfactant C12TAB was also able to modify the wetting conditions of chalk toward more water-wet conditions as the amount of natural petroleum base increased. (5) It was found that the dry outcrop chalk core initially contained some sulfate. The initial brine also contained a very small amount of sulfate. By draining with a porous plate to obtain 10% Swi, the sulfate was up-concentrated in the remaining water film, corresponding to a concentration of about one-third of the amount of sulfate in seawater. Sulfate probably prevented the carboxylic material from adsorbing, which resulted in rather water-wet cores. Hence, flooding the cores with distilled water prior to drying is necessary to be able to create reproducible wetting conditions for chalk. Acknowledgment. The authors acknowledge ConocoPhillips and the Ekofisk coventurers, including TOTAL, ENI, Hydro, Statoil, and Petoro, and the Valhall license including BP and Shell for financial support and for permission to publish this work. Also, thanks are due to the Norwegian Research Council, NFR, for support. Our gratefulness also goes to the M.Sc. students, Edwin A. Chukwudeme and Quincy Ogbeide, and also B.S. student Vidar Færevåg for their work included in this paper.

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Nomenclature AHeptane ) area between the thiocyanate curve and the reference heptane curve AN ) acid number ASTM ) american society for testing and materials AWett ) area between the thiocyanate curve and the sulfate curve BN ) base number Ca2+ ) calcium cation -COO- ) carboxylate group -COOH ) carboxylic acid group C12TAB ) dodecyl trimethyl ammonium bromide EF ) Ekofisk brine EOR ) enhanced oil recovery KOH ) potassium hydroxide Mg2+ ) magnesium cation N ) nitrogen atom N2 ) nitrogen gas OOIP ) oil originally in place PV ) pore volume SCN- ) thiocyanate anion Sor ) residual oil saturation SO42- ) sulfate anion SSW ) synthetic seawater with normal amount of sulfate ions present SSW-M ) synthetic seawater with sulfate and thiocyanate for wettability test SSW-U ) synthetic seawater without sulfate and thiocyanate for wettability test SSW/US ) synthetic seawater without sulfate SSW2S ) synthetic seawater with twice the normal concentration of sulfate SSW4S ) synthetic seawater with four times the normal concentration of sulfate Swi ) initial water saturation VB ) Valhall brine VB/US ) Valhall brine without sulfate WINew ) new wetting index wt % ) weight percent EF060624B

Water Flooding of Carbonate Reservoirs: Effects of ... - ACS Publications

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