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Energy & Fuels 2008, 22, 3222–3225
Effect of Temperature on Enhanced Oil Recovery from Mixed-Wet Chalk Cores by Spontaneous Imbibition and Forced Displacement Using Seawater Skule Strand,* Tina Puntervold, and Tor Austad UniVersity of StaVanger, StaVanger 4036, Norway ReceiVed April 8, 2008. ReVised Manuscript ReceiVed July 4, 2008
Seawater, as wettability modifier in chalk, has been studied at different temperatures and flooding conditions. Without sulfate initially present in the formation water, previous studies by spontaneous imbibition have shown that a temperature of about 100 °C is needed for the wettability modification to take place. The temperature plays a very important role for the chemical reactions taking place at the chalk surface and for the diffusion of active ions (Ca2+, Mg2+, and SO42-) into the chalk matrix. In the present study, the enhanced oil recovery using seawater was studied by both spontaneous imbibition and viscous flooding at 90, 110, and 120 °C. A crude oil of high acid number (AN ) 1.90 mg of KOH/g) was used to ensure a low, initial water wetness. At 90 °C, no difference in oil recovery using seawater and formation water in a spontaneous imbibition process was observed, but in the following viscous flooding process, seawater enhanced the oil recovery by 14% compared to formation water. At 110 and 120 °C, the impact of wettability modification using seawater became even more significant regarding oil recovery, but still, the viscous flood by seawater improved the oil recovery significantly compared to formation water. As a conclusion, improvements in oil recovery using seawater as a wettability modifier are obtained even at 90 °C, when displacing the oil by a viscous flood at low flooding rate.
Introduction At high temperature (>100 °C), seawater is able to improve the water wetness of chalk because of rock-fluid interactions and symbiotic interactions between Ca2+, Mg2+, and SO42-. This has been documented by increased oil recovery with seawater by spontaneous imbibition as well as by viscous flooding.1,2 The temperature is a critical parameter because it dictates the mutual affinity of the ions toward the chalk surface and also the diffusion rate into the porous medium. If the initial formation water is completely free from sulfate, previous studies have shown that there appears to be a minimum temperature of about 100 °C required to obtain significant oil recovery by spontaneous imbibition of seawater.3 The potential of seawater as a wettability modifier in chalk has also been documented by measuring the difference in the water-wetness before and after being exposed to seawater. After exposing a mixed-wet chalk core to a spontaneous imbibition process with seawater for about 30 days at 130 °C, the waterwet fraction of the core was increased from 0.6 to 1; i.e., it * To whom correspondence should be addressed. E-mail: skule.strand@ uis.no. (1) Puntervold, T.; Strand, S.; Austad, T. Co-injection of seawater and produced water to improve oil recovery from fractured North Sea chalk oil reservoirs. J. Pet. Sci. Eng. 2008, manuscript under review. (2) Zhang, P.; Tweheyo, M. T.; Austad, T. Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk: Impact of the potential determining ions: Ca2+, Mg2+ and SO42-. Colloids Surf., A 2007, 301, 199–208. (3) Puntervold, T.; Strand, S.; Austad, T. New method to prepare outcrop chalk cores for wettability and oil recovery studies at low initial water saturation. Energy Fuels 2007, 21 (6), 3425–3430.
became completely water-wet.4 A detailed chemical mechanism for the wettability modification has been proposed in a previous paper.2 In a previous study, a drastic increase in oil recovery was noticed when performing a viscous flood using seawater after first performing spontaneous imbibition and viscous displacement using produced water.1 The oil recovery using seawater increased from about 30 to about 65% of original oil in place. It is, however, important to note that the temperature of the flooding experiments was 110 and 130 °C. The outcrop cores were prepared using formation water without any sulfate and oils with moderate acid number (AN) of 0.70 and 1.1 mg of KOH/g, respectively. It is well-known that the water wetness of chalk decreases as the AN of the crude oil increases.5 Obviously, the substitution of produced water by seawater increased the capillary forces because of a wettability modification toward a more water-wet condition, which nearly doubled the oil recovery in a viscous displacement. Thus, the displacement of oil in a viscous flood using seawater appears to be very efficient because of improvements of the water wetness of the chalk surface. In comparison to a spontaneous imbibition process, the seawater, containing the active ions, Ca2+, Mg2+, and SO42-, is in a viscous flood forced into the chalk matrix, which facilitates the chemical processes responsible for the (4) Austad, T.; Strand, S.; Puntervold, T.; Ravari, R. R. New method to clean carbonate reservoir cores by seawater. Paper to be presented at the International Symposium of the Society of Core Analysts, Abu Dhabi, United Arab Emirates (UAE), Oct 29-Nov 2, 2008. (5) Standnes, D. C.; Austad, T. Wettability alteration in chalk. 1. Preparation of core material and oil properties. J. Pet. Sci. Eng. 2000, 28 (3), 111–121.
10.1021/ef800244v CCC: $40.75 2008 American Chemical Society Published on Web 08/29/2008
Oil RecoVery with Seawater As Wettability Modifier Table 1. Ionic Composition of FW and SW Used ions
FW (mol/L)
SW (mol/L)
HCO3ClSO42Mg2+ Ca2+ Na+ K+ TDS (g/L) IS (mol/L)
0.009 1.066 0.000 0.008 0.029 0.997 0.005 62.83 1.11
0.002 0.525 0.024 0.045 0.013 0.450 0.010 33.39 0.66
wettability alteration.2 Apparently, seawater does not appear to cause additional changes in the permeability of the chalk even at 130 °C.6 Injection of seawater into North Sea chalk reservoirs, Valhall (∼90 °C) and Ekofisk (130 °C), has been a tremendous success. BP has confirmed that seawater improved the oil recovery in both a spontaneous imbibition and a forced displacement process, by performing studies at complete reservoir conditions for the Valhall field. Thus, the whole capillary pressure curve was changed by exposing the reservoir cores to seawater compared to formation water.7 In this paper, we address the potential of oil recovery by spontaneous imbibition and viscous flooding of formation water and seawater at different temperatures. The question that we ask is as follows: “Is it possible to significantly increase the oil recovery at temperatures below 100 °C by performing a viscous displacement using seawater, or do we have to stay above 100 °C even in a viscous flood process?” The experiments were performed using an oil with a high AN ) 1.9 mg of KOH/g to have initial core conditions of very low water wetness. At each tested temperature (90, 110, and 120 °C), two cores were initially spontaneously imbibed with formation water. Then, one core was flooded with formation water followed by seawater, while the other core was spontaneously imbibed with seawater and finally flooded with seawater. The oil recovery was measured versus time for all processes, which allows for the presentation of oil recovery from all processes in the same diagram. Experimental Section Rock. Outcrop chalk from Stevns Klint, Denmark, was used. This chalk consists of 98% pure biogenic CaCO3, with high porosity (45-50%) and low matrix permeability (1-2 mD). It has a reactive large surface area of about 2 m2/g.8,9 The properties of the chalk are quite similar to those observed for the North Sea chalk oil reservoirs. Brines. Synthetic seawater (SW) and artificial formation water (FW) related to the Valhall field were used. The ionic composition of the brines is given in Table 1. The FW composition was received from BP. Oils. Two oils with different acid number (AN ) 1.9 and 0.7 mg of KOH/g) were used in the experiments. Stabilized Heidrun (6) Korsnes, R. I.; Madland, M. V.; Austad, T. Impact of brine composition on the mechanical strength of chalk at high temperature. EUROCK 2006sMultiphysics Coupling and Long Term BehaViour in Rock Mechanics; Taylor and Francis Group: London, U.K., 2006; ISBN 0 415 41001 0. (7) Webb, K. J.; Black, C. J. J.; Tjetland, G. A laboratory study investigating methods for improving oil recovery in carbonates. International Petroleum Technology Conference (IPTC), Doha, Qatar, 2005. (8) Frykman, P. Spatial variability in petrophysical properties in Upper Maastrichtian chalk outcrops at Stevns Klint, Denmark. Mar. Pet. Geol. 2001, 18 (10), 1041–1062. (9) Røgen, B.; Fabricius, I. L. Influence of clay and silica on permeability and capillary entry pressure of chalk reservoirs in the North Sea. Pet. Geosci. 2002, 8 (3), 287–293.
Energy & Fuels, Vol. 22, No. 5, 2008 3223 Table 2. Cumulative Oil Recovery by Spontaneous Imbibition (SI) and Viscous Flooding (VF) with FW and SW at Various Temperatures Using Crude Oil with AN ) 0.7 and 1.9 mg of KOH/g AN SI SI VF VF core T PV (mg of FW SW FW SW ID (°C) (cm3) Swi KOH/g) (% OOIP) (% OOIP) (% OOIP) (% OOIP) C#1 C#2 C#3 C#4 C#5 C#6 C#7
90 90 90 110 110 120 120
33.3 33.8 32.2 32.8 34.7 36.0 34.5
0.1 0.1 0.1 0.1 0.1 0.1 0.1
0.7 1.9 1.9 1.9 1.9 1.9 1.9
30.7 8.0 8.5 10.2 10.8 10.8 11.9
35.0 46.6 9.9 27.9 23.5 27.3 30.5
41.0 47.2 61.2 45.9 46.9 46.1 34.0
crude oil was diluted with 40 vol % n-heptane, centrifuged, and filtered through a 5 µm Millipore filter. The acid number was determined to be AN ) 1.9 mg of KOH/g. A sample of this oil was treated with silica to remove polar components as described previously,10 giving an oil with AN ) 0.10 mg of KOH/g. These two oils were mixed to give the oil with AN ) 0.70 mg of KOH/ g. The density and viscosity of the two oils were determined to be quite similar at 20 °C, i.e., 0.800 g/cm3 and 2.5 cP, respectively. Core Preparation. Chalk cores with a length of about 65 mm and diameter of about 38 mm were prepared according to the method described in a previous paper.3 The cores were flooded with distilled water to remove any dissolvable salts, especially sulfates, and then saturated with FW. The cores were drained by watersaturated N2 gas to Swi ∼ 0.10 by the porous plate technique. Homogeneous oil saturation was established by flooding the core in a Hassler core holder with 1.5 PV of oil in each direction. The cores were wrapped in Teflon tape to avoid unrepresentative adsorption of polar components onto the surface during the aging process in the actual crude oil at 90 °C for 4 weeks in a sealed steel container. The core data are listed in Table 2. Spontaneous Imbibition/Forced Displacement. After aging, each core was transferred to a sealed steel imbibition cell and surrounded with the imbibing fluid. The spontaneous imbibition test (SI) was performed at the specified temperature with a constant back pressure of ∼10 bar. The produced oil was collected in a burette, and the volume was recorded as a function of time. After the imbibition test was completed, the core was transferred to a Hassler core holder to undergo forced displacement, also referred to as viscous flooding (VF). The core was placed in a rubber sleeve with a confining pressure of ∼20 bar and a back pressure of ∼10 bar. The injection fluids were pumped at a controlled rate of 0.06-0.12 PV/day. The differential pressure (∆P) across the core varied from a maximum of 6 psia at the start to a minimum of 1 psia at the end, depending upon the test temperature and water saturation. The produced fluid was collected in a burette, and the oil recovery was calculated as a function of time to plot the data in the same plot as the imbibition data. At each temperature, 2 cores were tested. Both cores were first spontaneously imbibed with FW. After the oil production plateau in the spontaneous imbibition process was reached, i.e., oil production had stopped, the imbibition fluid in one of the cores was changed to SW, to undergo a new spontaneous imbibition process, and then followed by viscous flooding, VF, with at least 1 PV of SW. The other core was flooded with at least 1 PV of FW and then continued with a new viscous flooding with at least 1 PV of SW.
Results and Discussion The cores used in the experiments were prepared from the same outcrop chalk block, and they were very homogeneous regarding permeability and porosity. In that sense, the material is excellent for doing parametric studies. (10) Puntervold, T.; Strand, S.; Austad, T. Water flooding of carbonate reservoirs: Effects of a model base and natural crude oil bases on chalk wettability. Energy Fuels 2007, 21 (3), 1606–1616.
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Figure 1. Oil recovery from chalk core C#1 at 90 °C by successive spontaneous imbibition of FW, forced displacement using FW, and finally forced displacement using SW. The injection rate was low, in the range of 0.06-0.12 PV/day, with a ∆P across the core of 4 psi at the start and 2 psi at the end. Swi ∼ 0.1, and AN ) 0.70 mg of KOH/g.
Figure 2. Oil recovery from the cores C#2 and C#3 at 90 °C by successive spontaneous imbibition and forced displacement. The injection rate was in the range of 0.08-0.12 PV/day, and the ∆P across the core varied from 6 at the start to 2 psi at the end. Swi ∼ 0.1, and AN ) 1.9 mg of KOH/g.
Oil Displacement at 90 °C. The acid number of the crude oil is the most important wetting parameter for carbonates.5 To illustrate the effect of AN on the oil recovery, a core was prepared using initial formation water and a crude oil with AN ) 0.70 mg of KOH/g (Figure 1). The core termed C#1 was spontaneously imbibed with FW at 90 °C, and the oil recovery was slightly above 30% OOIP, which points to a moderate water-wet condition. Forced displacement using FW increased the cumulative oil recovery to 35% OOIP. When the injected fluid was switched to SW, there was a significant increase in oil recovery. The flooding was terminated after an injection of 1.2 PV, with an oil recovery of 41% OOIP. At that time, however, the plateau recovery was not obtained. The forced displacement rate was low, in the range of 0.06-0.09 PV/day, to allow the injected SW to react with the chalk surface to improve the water wetness. When the AN of the crude oil was increased to 1.90 mg of KOH/g, the spontaneous imbibition of FW at 90 °C into the two cores (C#2 and C#3) was much lower. The oil recovery was only 8.5% OOIP (Figure 2). As expected, the water wetness decreased drastically as the AN of the crude oil increased from 0.70 to 1.90 mg of KOH/g. After about 20 days of imbibition, the core termed C#2 was subjected to forced displacement with FW, and the plateau recovery reached 46.6% OOIP after 0.7 PV injected. Flooding with SSW (1.0 PV) at this stage did not
Strand et al.
Figure 3. Oil recovery from the cores C#4 and C#5 at 110 °C by successive spontaneous imbibition and forced displacement. The injection rate was in the range of 0.06-0.10 PV/day, and the ∆P across the core varied from 6 at the start to 3 psi at the end. Swi ∼ 0.1, and AN ) 1.9 mg of KOH/g.
Figure 4. Oil recovery from the cores C#6 and C#7 at 120 °C by successive spontaneous imbibition and forced displacement. The injection rate was in the range of 0.09-0.12 PV/day, and the ∆P across the core varied from 5 at the start to 1 psi at the end. Swi ∼ 0.1, and AN ) 1.9 mg of KOH/g. At 66 days, C#7 was flooded with SW at a high rate (∆P e 10 psi).
result in any extra oil recovery, because it is very difficult to mobilize the residual oil at such a high water saturation. The core termed C#3 was imbibed by SW for a long time, i.e., about 60 days, but the oil recovery was very small. The cumulative oil recovery was less than 10% OOIP. Finally, the core was flooded with SW, and the recovery reached 60% after injecting 0.7 PV. After an injection of 1.1 PV, the oil recovery was 61.2% OOIP, indicating that the oil recovery plateau was reached. Thus, the final recovery of the core flooded with SW (C#3) was 14% higher than the core flooded with FW (C#4). The reason is that SW, in addition to Ca2+ and Mg2+, also contained SO42-, which was absent in the FW. Thus, even at 90 °C, the effect of SW on the oil recovery is enhanced by performing a viscous flood, but the improved oil recovery was negligible when performing a spontaneous imbibition. Oil Displacement at 110 °C. First, the two cores (C#4 and C#5) were imbibed with FW, and the oil recovery was in the range of 10% OOIP. The core C#4 was then flooded with FW, and the cumulative oil recovery reached 27.5% OOIP after 0.7 PV injected (Figure 3). When the flooding fluid was switched to SW, the oil recovery immediately increased to 46% OOIP after 1.3 PV injected. The experiment was, however, terminated before the oil recovery plateau was reached. After spontaneous imbibition of FW, the core C#5 was exposed to SW in a spontaneous imbibition process for a very long time, about 65 days (Figure 3). The cumulative oil recovery
Oil RecoVery with Seawater As Wettability Modifier
reached 23.5% OOIP. Finally, the core was flooded with SW, and the experiment was terminated when the oil recovery reached 47% OOIP after 1.4 PV injected. Thus, also when using SW at 110 °C, the efficiency of oil recovery is greater in a viscous flood compared to a spontaneous imbibition process. Oil Displacement at 120 °C. Spontaneous imbibition of the cores C#6 and C#7 using FW as imbibing fluid resulted in an oil recovery of about 11% OOIP after nearly 20 days (Figure 4). The core termed C#6 was next flooded with FW, and the plateau recovery increased to 28% OOIP after 0.7 PV injected, similar to what was obtained at 110 °C. A sudden increase in oil recovery was detected when the flooding fluid was changed to SW. The experiment was stopped when the recovery reached 46% OOIP after injecting 1.6 PV without reaching the ultimate plateau recovery. After spontaneous imbibition with FW, core C#7 was imbibed with SW for about 35 days and the cumulative oil recovery reached 30% OOIP. At that time, the spontaneous imbibition plateau was not obtained. Even at this high temperature, the imbibition rate with SW was very slow and the core appeared to be preferentially oil-wet because of the high AN. Following spontaneous imbibition of SW, the core was next exposed to a viscous displacement by SW at a very low rate. The differential pressure over the core varied between 1.5 and 2.0 psi. About 1.5 PV was injected over approximately 12 days, but the oil recovery only increased with 4%. The slow injection was performed to test if the injected SW could imbibe into areas not contacted by wettability alteration. As a final step, the viscous forces were increased by increasing the differential pressure over core C#7 to 10 psi, and a sudden increase in oil recovery was noticed (Figure 4). After 2 PV of SW had been injected at maximum ∆P ∼ 10 psi (3.5 PV in total), the oil recovery stabilized at 50% OOIP. The drastic increase in oil recovery by increasing the pressure gradient when flooding with seawater cannot be explained by only an increase in capillary number because of higher viscous forces. The result is rather believed to be related to end effects, which could have been tested by increasing the differential pressure gradually, but unfortunately, this was not performed. The end effects will increase as the core becomes more water-wet. This may also be reflected in the somewhat higher residual oil saturation observed in these experiments compared to previous observations. Any way, the efficiency in oil recovery by using SW is higher when performing a viscous flood compared to a spontaneous imbibition. Thus, the chemical reactions related to the wettability modification are faster when the components responsible for the wettability modification are forced into the chalk matrix. It is, however, worth noting that some outcrop chalk, such as Aalborg chalk (sometimes also termed Rørdal chalk), contains significant amounts of silica distributed across the surface. Because of surface charge differences between chalk and silica at natural pH, this type of chalk has different wetting properties toward crude oil as stated by Strand et al.11 The surface area (11) Strand, S.; Hjuler, M. L.; Torsvik, R.; Pedersen, J. I.; Madland, M. V.; Austad, T. Wettability of chalk: Impact of silica, clay content, and mechanical properties. Pet. Geosci. 2007, 13, 69–80.
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appeared to be nearly completely water-wet when exposed to crude oil, and therefore, a wettability alteration by seawater will probably not take place. It should be noted that this type of silica has not been observed in reservoir chalk samples so far. Conclusions Enhanced oil recovery from chalk by wettability modification using SW is very restricted to the temperature because of strong solvent-ion interactions, in the case of SO42- and Mg2+. Sulfate is solvated by hydrogen bonding and Mg2+ is strongly hydrated by six water molecules. At temperatures in the range of 100 °C, the degree of hydration decreases, hydrogen bonds break, and the ions become more reactive. Sulfate adsorbs more strongly onto the chalk surface, which is a “must” for the displacement of strongly adsorbed carboxylic material in the presence of Ca2+ and/or Mg2+. The conclusions from the present work are shortly summarized as follows: (1) At 90 °C, it appears that significant enhanced oil recovery by wettability modification by SW is only possible by a viscous flood. The oil recovery was increased by 14% OOIP when flooding with SW compared to FW, which was free from SO42-. (2) At 110 and 120 °C, increased oil recovery by spontaneous imbibition of SW is observed as the temperature increases, but still, viscous displacement is more efficient. (3) Enhanced oil recovery from a naturally fractured oil-wet chalk reservoir with Tres < 100 °C is difficult to achieve, because the fluid exchange between the fractures and the matrix blocks relies on positive capillary forces. The wettability alteration by SW appears to be too slow. (4) In a nonfractured oil-wet chalk reservoir, significant improvements in oil recovery can be achieved by performing a viscous flood with SW even at 90 °C. An increase of 14% OOIP was observed when using SW compared to FW. Acknowledgment. The authors acknowledge ConocoPhillips and the Ekofisk coventurers, including TOTAL, ENI, StatoilHydro, and Petoro, and the Valhall partnership, including BP Norge AS, Amerada Hess Norge AS, A/S Norske Shell, and Total E&P Norge AS, for financial support. In addition, thanks are due to the Norwegian Research Council (NFR) for support.
Nomenclature AN ) acid number, mg of KOH/g FW ) formation water IS ) ionic strength, mol/L OOIP ) original oil in place, cm3 PV ) pore volume, cm3 SI ) spontaneous imbibition SW ) seawater Swi ) initial water saturation, fraction or % TDS ) total dissolved solids, g/L Tres ) reservoir temperature VF ) viscous flooding ∆P ) pressure gradient over the core EF800244V
