Apr 13, 2016 - This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by ...
SPE-179674-MS Effect of Rock Aging on Oil Recovery during Water-Alternating-CO2 Injection Process: An Interfacial Tension, Contact Angle, Coreflood, and CT Scan Study R. Ramanathan, A. M. Shehata, and H. A. Nasr-El-Din, Texas A&M University
Copyright 2016, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Improved Oil Recovery Conference held in Tulsa, Oklahoma, USA, 11–13 April 2016. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract Wettability of the rock is an important parameter in determining oil recovery. It determines the fluid behavior and the fluid distribution in the reservoir. Aging of the rock changes the wettability of the rock and can affect the residual oil saturation. This paper investigates the effect of aging on the oil recovery during the Water-Alternating-CO2 injection (WACO2) process using 20 in. outcrop Grey Berea sandstone cores under immiscible conditions. In the present work, two coreflood experiments were performed. Both cores were aged for a period of 30 days at 149°F. This study is a continued research and compares the performance of WACO2 injection in aged cores to previously published work with unaged cores. All experiments were done at 500 psi and in the secondary recovery mode. The wettability of the Rock- Brine-CO2-Oil system for aged cores was determined by contact angle measurements using formation brine (174,156 ppm), seawater brine (54,680 ppm) and low-salinity brine (5,000 ppm NaCl). The interfacial tension (IFT) of the Brine-Oil-N2 and Brine-Oil-CO2 system was also measured using the axisymmetric drop shape analysis (ADSA) method. Computerized tomography (CT) scans were obtained for each core in its various states: dry state, 100% water-saturated state, oil saturated state with irreducible water saturation, and residual oil-saturated state. The CT scans were used to determine the porosity profile of the cores. The contact angle measurements of the Rock - Brine - CO2 - Oil system indicated an increase in contact angles after the aging of the cores. Low-salinity brine showed the most water-wet state (55°) and seawater brine showed the most oil-wet state (96°) of the rock. This may be because of the increased concentration of divalent ions on the surface of the rock during seawater brine injection. Ion binding is the dominant mechanism in the oil-wet nature of the rock. The previously published work stated that the coreflood experiments of the unaged cores resulted in an oil recovery of 61.7 and 64.6% OOIP during low-salinity water-alternating-CO2 and seawater-alternating-CO2 injection, respectively. In aged cores, the oil recovery increased to 97.7 and 76.1% OOIP during the low-salinity water-alternating-CO2 and seawateralternating-CO2 injection, respectively. The improved oil recovery was attributed to the wettability alteration when the rock was aged.
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The interfacial tension measurements of brine/oil/nitrogen and brine/oil/CO2 systems showed that the salinity of the brine had an effect on the IFT. Low-salinity brine (5,000 ppm) yielded the highest IFT values and seawater brine produced the least. Monovalent ions had a weak effect on the interfacial activity between the oil and the brine. When multivalent ions were present, the IFT values were influenced by the salting effect of the brines. During the IFT measurements of brine/oil/CO2 system, the IFT values showed an increasing trend as a function of time and then stabilized. The increase in IFT was because of the initial mass transfer between the CO2, brine, and oil phases.
Introduction The wettability of a reservoir is a key parameter in projecting the oil recovery and the residual oil saturation. The wettability of the rock is in direct relationship with the capillary pressure, relative permeability, and phase distribution in the pore spaces (Kaveh et al. 2012). Aging the rock has shown to modify its wettability (Jadhunandan and Morrow 1995; Chattopadhyay et al. 2002; Ramanathan et al. 2015). The relationship of the wettability alteration to oil recovery has been debated in literature; some authors have reported wettability alteration to a more intermediate-wet state as the possible mechanism leading to improved oil recovery, whereas others have reported a wettability change to a more water-wet state as the reason. Contact angle measurements have been proven to be the best method to determine the wettability of the rock under different pressure and temperature conditions (Kaveh et al. 2012). The stability of the water film between the rock and the oil is said to be a crucial factor in determining the extent of oil recovery from the rock (Hirasaki 1991). The thickness of the film has an effect on the longevity of oil production and ultimately on oil recovery. Adsorption of polar oil components onto the rock surface via ion binding has been hypothesized in the past to increase the contact angle (Buckley and Liu 1998; Ramanathan et al. 2015). The capillary number is also influenced by the interfacial tension of the fluids. The mobility of the trapped oil is directly proportional to the capillary number. To increase the mobility and hence the oil recovery, the IFT between the oil and brine must be decreased. IFT can be measured by different methods such as spinning drop, sessile drop, and pendant drop methods (Moeini et al. 2014). Among these methods, the pendant drop method is most widely used because of its limited sample requirement, and because it is the fastest method to measure IFT. Limited research has been conducted on the role of salinity of brine on the IFT. Bachu and Bennion (2009) conducted experiments to measure the IFT between CO2 and brine of different salinities. Okasha and Al-Shiwaish (2009) performed IFT measurements between a 30 °API oil and brine of varying salinities. All the brines they used had multivalent ions, and the lowest salinity was 52,346 ppm. The impact of brine salinity on the IFT with live oil was discussed by Yousef et al. (2011) who conducted the study with brines having salinity range of 576 ppm to 213,734 ppm. They observed that there was no significant change in the IFT values when the salinity was reduced below 50,000 ppm. The effect of rock aging on oil recovery during waterflooding and wettability has been investigated in the past (Jadhunandan and Morrow 1995; Zhou et at. 2000; Chattopadhyay et al. 2002; Ramanathan et al. 2015). Jadhunandan and Morrow (1995) stated that the oil recovery improves when the rock is aged as a result of reduced capillary forces. However, they also stated that it does not change if the aging period is greater than twenty days. There is a common consensus that the reduction of water-wetness in the rock leads to the improved oil recovery. The mixed-wetness of the rock leads to more unstable oil layers with larger amount of continuous oil (Alagic et al. 2011). Eide et al. (2015) stated that aging the rock would create oil saturated pore throats in the rock which could change the wettability towards a mixed-wet state. Computerized Tomography (CT) scan studies are useful to observe the in-situ displacement processes in coreflood experiments (Peters and Hardham 1990). It is a technique that uses X-rays to generate cross-sectional images of the rock at angular increments within a single plane (Akin and Kovscek 2003).
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The linear attenuation coefficient is obtained from Beer’s law when an incident X-ray intensity I0 passes through a sample of thickness h and the final reduced intensity is I. Beer’s law is given is given as: (1) This paper discusses the effect of aging on the WACO2 process through contact angle measurements, interfacial tension measurements, coreflooding tests, and CT imaging. The effect of salinity of injected brine during WACO2 is also discussed.
Materials Cores Two cylindrical cores of 20 in. length and 1.5 in. diameter were cut from a homogenous Grey Berea sandstone block. The porosity and permeability of the cores were measured using a coreflood setup. Table 1 gives the petrophysical properties of the cores. Previously published work used two unaged cores cut from the same homogenous Grey Berea sandstone rock. Table 1 also includes the petrophysical properties of those cores.
Table 1—Petrophysical properties of the Grey Berea sandstone cores. Core ID
RSR 20 (Unaged Core)
RSR 22 (Unaged Core)
RSR 25 (Aged Core)
RSR 30 (Aged Core)
Length (in.) Porosity (vol%) Brine permeability (md) Connate water saturation (%) Initial oil saturation (%)
20 17.7 73.2 42 58
20 19.1 77.7 43 57
20 18 89.5 29 71
20 18.9 53.2 42 58
Fluids Three different salinities of synthetic brine were prepared by dissolving predetermined salts in deionized water of resistivity 18.2 M⍀.cm. The salinity of the brines replicated a Middle Eastern reservoir brine. Table 2 gives the composition of each brine. Table 3 gives the density of each brine at various temperatures and atmospheric pressure.
Table 2—Composition of prepared brines. Salt
Formation Brine (mg/l)
Seawater Brine (mg/l)
Low-salinity Brine (mg/l)
NaCl CaCl2.2H2O MgCl2.6H2O Na2SO4 NaHCO3 Total dissolved solids (TDS)
137,735.01 38,881.86 13,463.63 547.08 242.32 174,156
38,386.284 2,435.618 19,058.138 5,263.816 265.722 54,680
5,000 – – – – 5,000
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Table 3—Density of prepared brines and crude oil at 14.7 psi. Temperature (°F)
Crude Oil (g/cm3)
Formation Brine (g/cm3)
Seawater Brine (g/cm3)
Low-Salinity Brine (g/cm3)
77 86 95 104 113 122 131 140 149 158 167 176
0.8114 0.8078 0.8042 0.8006 0.797 0.7934 0.7898 0.7862 0.7826 0.77895 0.7753 0.7716
1.1409 1.1382 1.1313 1.1288 1.1262 1.1235 1.1207 1.1176 1.1145 1.1107 1.1071 1.1048
1.0398 1.0381 1.0362 1.0342 1.032 1.0297 1.0272 1.0246 1.0203 1.0116 1.005 0.9983
1.0022 1.0007 0.9991 0.9972 0.9952 0.9923 0.9898 0.987 0.9841 0.9809 0.9775 0.974
A crude oil with a density of 41 °API was used for all the experiments. It was centrifuged at 3000 rpm for 20 minutes to separate the oil from suspended solids and aqueous phase. The density of this oil at different temperatures is also given in Table 3. Carbon dioxide of 99.8% purity was used for the WACO2 coreflooding experiments and nitrogen of 99.9% purity was used to apply backflow and overburden pressure during the coreflood experiments.
Rock Characterization The composition of the Grey Berea sandstone rock (Table 4) was determined using X-ray diffraction (XRD), scanning electron microscopy (SEM), and X-ray fluorescence (XRF). According to literature, the kaolinite content in Grey Berea sandstone was higher than Buff Berea, Parker, and Bandera.
Table 4 —Mineralogy of Grey Berea sandstone cores. Mineral
Concentration (wt%)
Quartz Kaolinite Albite Illite Calcite
87 6 3 2 2
Experimental Setup and Procedure Interfacial Tension Measurement A Drop Shape Analyzer (DSA) measured the interfacial tension in an Oil/Brine system. The components of the DSA are demonstrated in Fig. 1. The procedure to prepare the apparatus for the measurement of IFT consists of the following steps:
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Figure 1—A schematic diagram of the drop shape analyzer used in this study.
1. The High Pressure/High Temperature (HP/HT) cell was cleaned using deionized water and completely dried using sensitive tissues. 2. Viewing windows were then locked in place, and the brine was injected into the cell using a syringe. 3. The cell was pressurized to 500 psi using either nitrogen (IFT vs. Temperature) or CO2 (IFT vs Time) based on the experiment conducted. 4. The temperature of the system was measured using a thermocouple. 5. A syringe pump injected oil into the cell and a pendant drop was formed at the tip of the needle. An image of the pendant drop was obtained through the image acquisition system and sent to the computer for analysis. Drop shape analysis software determined the IFT of the system using the Laplace equation for capillarity.
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6. After the experiment, the cell was evacuated through the discharge valve and cleaned thoroughly with deionized water. Contact Angle Measurement The DSA was used to measure the contact angle of Aged Rock/Brine/Oil/CO2 systems. Three rock substrates of size 0.62 in. x 0.72 in. x 0.25 in. were cut from a core plug for its use in these experiments. The rock substrates were prepared by the following procedure: 1. The rock lateral substrates were polished using sandpaper of two mesh sizes (P220 and P400). 2. The substrates were then kept in formation brine for a period of one day, after which they were subjected to vacuum pressure for four hours. The substrates were then kept in the brine for another two days. 3. The substrates were then saturated with crude oil using a centrifuge. After the substrates were placed in three different tubes filled with crude oil, the centrifuge was run at 3,000 rpm for thirty minutes. This was done twice to ensure complete saturation of the rock substrates. 4. Aging was done by keeping the rock substrates in crude oil inside an oven at 149°F for 30 days. The preparation process for the contact angle measurements was similar to that done for the IFT measurements except that a rock substrate holder along with the substrate was installed in the HP/HT cell prior to closing it. The pressurizing medium was CO2 at 500 psi. A drop of oil was formed on the needle and allowed to attach to the substrate. The drop shape analyzer determined the angle between the baseline and the tangent at the drop boundary. Coreflood Experiment Fig. 2 shows the schematic diagram of the coreflood setup. Both the cores were prepared in the same way. Firstly, the 20 in. core was cut from a Grey Berea sandstone outcrop block and dried at 250°F till the daily measured weight did not change. The cores were kept in formation brine for one day before applying vacuum to remove the air pockets in the cores. The vacuum pressure was applied for four hours. After the vacuum pressure was released, the cores were kept in the formation brine for at least 10 days to achieve ionic equilibrium.
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Figure 2—A schematic diagram of the coreflood setup used in this study.
The core was loaded into the core holder and prepared for permeability measurement. After the overburden pressure of 1,000 psi and backflow pressure of 500 psi were applied, formation brine was injected into the core. The pressure drop vs. time was recorded using the LabVIEWTM software. The formation brine was injected into the core at five different flow rates: 0.5, 1, 1.5, 2, and 5 cm3/min. Darcy’s law was used to calculate the permeability using the known values of the stable pressure drop at its corresponding injection flow rate. The porosity of the core was found by calculating the difference in the weight of the saturated core and that of the dry core and dividing it by the density of the formation brine.
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The core was later saturated with crude oil using the same coreflood setup. The overburden pressure was set at 1,500 psi and the backflow pressure was set at 400 psi. Crude oil was injected into the core at the following flow rates: 0.1, 0.2, 0.5, 1, 2, and 3 cm3/min. The flooding at each flow rate continued till no water was found in the effluent tubes. The cores were then aged at 149°F and atmospheric pressure for a period of 30 days in a sealed steel pipe filled with crude oil. For the WACO2 experiments, the aged core was firstly removed from the sealed steel pipe and the bulk oil was cleaned from the core. The core was then installed in a 20 in. core holder, which was kept in a high temperature oven. The backflow pressure and overburden pressure were applied to the core and the temperature of the oven was set to 149°F. The system was allowed to achieve thermal equilibrium for two hours. Both brine and CO2 accumulators were kept outside the oven at the ambient temperature condition. CO2 was injected at 500 psi from a compressed cylinder into the accumulator for at least 20 minutes to reach equilibrium. The accumulator valve was then closed and the CO2 cylinder was isolated from the coreflood setup. Brine and CO2 were then injected alternately into the bottom end of the core using a Teledyne syringe pump, the first slug being the brine. The fluids were injected in four cycles at different flow rates: 0.5, 1, 2, and 4 cm3/min. The oil recovery and pressure drop across the core were monitored for each slug of injected fluid. Computerized Tomography (CT) Scanning To determine the porosity and fluid saturation profiles of the cores, CT scans were conducted at each stage of core preparation: initial dry core, after the water saturation, after the oil saturation, after the aging period of the core, and after the WACO2 experiment. Following this, the obtained CT-numbers were used in correlations given by Bataweel et al. (2011) to calculate the porosity using the equation below: (2) where ⌽ is the porosity (fraction), CTwsat is the CT-number of 100% water saturated core, CTdry is the CT-number of the dry core, CTw is the CT-number of the brine, and CTA is the CT-number of the air.
Results and Discussion Interfacial Tension Measurement Six experiments were conducted to evaluate the effect of temperature and time on the IFT of the brine/oil system. The different brines used in both the studies included formation brine (174,156 ppm), seawater brine (54,680 ppm), and low-salinity brine (5,000 ppm NaCl). Through these experiments, the effect of brine salinity on the IFT was also discussed. The equilibrium IFT was measured at different temperatures for each brine. Measurements were taken at 77-176°F at every 9°F intervals. This experiment was done using nitrogen at 500 psi as the pressurizing medium. To avoid the possibility of mass transfer between the phases, the system was allowed to attain thermodynamic equilibrium by measuring the IFT after 15 minutes of contact at each temperature. Dynamic IFT was measured at 149°F using CO2 at 500 psi as the pressurizing medium. The experiment was performed for a total time period of four hours, and the IFT measurements were done every fifteen minutes to evaluate the change in IFT over time. The drop volume was closely monitored to check the drop stability profile. Formation brine, seawater brine, and low-salinity brine was used in this experiment as well. Effect of Injected Brine Salinity on IFT Figs. 3 and 4 represents the IFT measurements of a brine/oil system with different kinds of brines. The system pressure was kept constant at 500 psi. The drop volume was nearly the same for all the measurements. From these measurements, it was evident that low-salinity brine had the highest IFT and seawater brine had the lowest. Bai et al. (2010) stated that monovalent ions has a weak effect on the interfacial activity between the oil and the brine and most of the interfacial active
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substances are oil-soluble, hence not able to participate in the interfacial interactions. Seawater brine and formation brine experience the salt effect (Moeini et al. 2014), which is explained below. The Gibbs adsorption isotherm, which relates the interfacial energy with the composition of the system, is given by the following equation: (3)
Figure 3—Effect of temperature on the equilibrium interfacial tension of crude oil/brine/nitrogen system at 500 psi.
Figure 4 —Effect of time on the dynamic interfacial tension of crude oil/brine/CO2 system at 500 psi and 149°F.
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where d␥ represents the change in interfacial tension, R is the universal gas constant, T denotes the absolute temperature, represents the surface charge excess concentration, and ␣ stands for chemical activity of the chemical component. When the salinity of the injected brine is increased, it causes a disruption of hydrogen bonds at the interface between the oil phase and the water phase. This creates an energy gradient and causes the inorganic salt ions to go into the bulk phase. The surface excess concentration becomes negative, and, hence, the change in interfacial tension becomes positive, which means that there will be an increase in the IFT. Since formation brine has a higher concentration of salts than seawater brine, it has a higher interfacial tension than seawater brine. From the IFT results, seawater brine produces the lowest interfacial tension, which is beneficial for oil recovery applications. The role of IFT doesn’t influence the improved oil recovery obtained during low-salinity brine injection. The effect of temperature on the IFT for all the brines had a similar trend. As the temperature increased, the IFT of the oil/brine system increased as well. As pointed out by Hjelmeland and Larrondo (1986), there will be a lower concentration of the surface-active components at the brine/oil interface at higher temperatures, and this may be the cause of the higher IFT. Fig. 3 presents the IFT vs temperature graph for all the brines used in this study. Dynamic interfacial tensions of the brine/oil/CO2 systems were measured as a function of time at 149°F. The ADSA method was used to measure the interfacial tension of the brine/oil/CO2 system. Fig. 4 shows the interfacial tension vs. time values for low-salinity brine, seawater brine, and formation brine. The measurements were taken at every fifteen minute interval for three hours. For all the brines, the IFT first increased and then became stable. The drop volume was also measured, and it followed the trend of the IFT. The dissolution of the CO2 in the brine and oil phase resulted in the initial increase in the IFT values. When there was no mass transfer between the phases, equilibrium existed and the IFT values stabilized. Contact Angle Measurements This section presents a continued research to investigate the effect of rock aging on the wettability. A drop shape analyzer was used to measure the contact angle of the rock at 500 psi. The effect of time on the contact angle of the rock was studied using a rock/brine/oil/CO2 system at 149°F and 500 psi. Ramanathan et al. (2015) presented the results of this experiments using unaged cores only. The present work demonstrates the results of the same experiment using aged cores. The rock was aged in crude oil at 149°F for thirty days before its use in the experiments. From the previous work of Ramanathan et al. (2015), it was noted that the dynamic contact angles fluctuated with time and finally reached an equilibrium value. The fluctuations were due to several factors discussed in that paper. Fig. 5 shows the contact angle measurements of the aged rock/brine/oil/CO2 system as a function of time. Seawater brine had the highest contact angle, which stabilized after 1,020 minutes of contact. Low-salinity brine (5,000 ppm NaCl) produced the most water-wet state among the three brines. The contact angle stabilized after 840 minutes of contact. Formation brine took 1,260 minutes to produce stable contact angles.
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Figure 5—Effect of time on the dynamic contact angle of aged rock/oil/brine/CO2 system at 500 psi and 149°F.
For aged cores, the dynamic contact angles were much higher than those of the unaged cores. The wetting state of the aged system became more oil-wet relative to the wetting state of the unaged system. From the previous study concerning unaged cores, the equilibrium contact angle value for each brine was close to one another. When formation brine is considered as the connate water, there was no significant wettability alteration when low-salinity brine or seawater brine was injected into the unaged core during the water-alternating-CO2 injection process. However, low-salinity brine showed a significant change in the wetting state in aged cores. Formation brine produced an equilibrium contact angle of 84° whereas low-salinity brine gave a contact angle of 55°. There was a wettability alteration towards a more water-wet state when low-salinity brine was used in the water-alternating-CO2 injection process. Coreflood Experiments Two coreflood experiments were conducted in this work. A low-salinity brine-alternating-CO2 flood and a seawater brine-alternating-CO2 flood were done using 20 in. length aged Grey Berea sandstone cores. The oil recovery and pressure drop were evaluated and discussed. The backflow pressure and overburden pressure were kept at 500 and 1,500 psi, respectively. The temperature of the experiments was maintained at 149°F. The recovery process was initiated in the secondary mode at initial oil saturation, Soi. These experiments with aged cores were designed to evaluate the effect of rock aging on the oil recovery by comparing its performance against similar experiments conducted by Ramanathan et al. (2015) with unaged cores. Effect of Rock Aging on Oil Recovery during WACO2 injection In this work, two cores named RSR 25 and RSR 30 were cut from the same block of Grey Berea sandstone outcrop. They were prepared in the same manner as stated in this paper. RSR 25 was subjected to low-salinity water-alternating-CO2 injection (Experiment A-7) and RSR 30 was flooded with seawater brine and CO2 in alternate slugs (Experiment A-8). Experiment A-7 led to an oil recovery of 97.7% OOIP and 60% of the oil was recovered in the first slug of brine injection. The first slug of CO2 injection at 0.5 cm3/min recovered 14.5% OOIP. The second slug of brine recovered 14% OOIP and the second slug of CO2 recovered another 2.4% OOIP. The third cycle of injection yielded 6.8% OOIP and there was no recovery during the fourth cycle of injection. An
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additional slug of brine was injected at 4 cm3/min to make sure that the residual oil saturation was reached. The water cut was observed to be greater than 99% for several pore volumes before the end of the experiment. Fig. 6 represents the cumulative oil recovery against the injected pore volume. The values of the experiment are tabulated in Table 5.
Figure 6 —Oil recovery and pressure drop across the aged core for experiment A-7 at 149°F. The injection was performed with the low-salinity-brine-alternating-CO2. The vertical dashed lines separate the different injection stages. Table 5—Summary of coreflood experiment (A-7) for aged Grey Berea sandstone at 149°F.
Slug No. 1 2 3 4 5 6 7 8 9
Slug Type NaCl (5,000 ppm) CO2 NaCl (5,000 ppm) CO2 NaCl (5,000 ppm) CO2 NaCl (5,000 ppm) CO2 NaCl (5,000 ppm)
Slug Size (PV)
Incremental Oil Recovery (%OOIP)
Total Oil Recovery (%OOIP)
0.5
3.5
60.0
60.0
0.5 1
3.1 3.1
14.5 14.0
74.5 88.5
1 2
3 3.3
2.4 6.8
90.9 97.7
2 4
4 3.9
0.0 0.0
97.7 97.7
4 4
3.6 3.7
0.0 0.0
97.7 97.7
Recovery Mode
Injection Rate (cm3/min)
Secondary
76.1% OOIP was recovered during experiment A-8. The first slug of brine injection recovered 38.1% OOIP and the first CO2 slug recovered 13.9% OOIP. The second slugs of brine and CO2 injection yielded 11.4% and 2.5% OOIP, respectively. An incremental oil recovery of 6.7% OOIP was recovered during the
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third slug of brine injection. An additional 1.9% OOIP was recovered during the third slug of CO2 injection. The forth slug of brine recovered 1.6% OOIP and there was no further oil production. Fig. 7 represents the cumulative oil recovery against the injected pore volume. Table 6 gives the values of the experiment.
Figure 7—Oil recovery and pressure drop across the aged core for experiment A-8 at 149°F. The injection was performed with the seawater-brine-alternating-CO2. The vertical dashed lines separate the different injection stages. Table 6 —Summary of coreflood experiment (A-8) for aged Grey Berea sandstone at 149°F.
Slug Size (PV)
Incremental Oil Recovery (%OOIP)
Total Oil Recovery (%OOIP)
Slug No.
Slug Type
Recovery Mode
Injection Rate (cm3/min)
1
Seawater Brine (54,680 ppm) CO2 Seawater Brine (54,680 ppm) CO2 Seawater Brine (54,680 ppm) CO2 Seawater Brine (54,680 ppm) CO2 Seawater Brine (54,680 ppm)
Secondary
0.5
3.1
38.1
38.1
0.5 1
2.9 2.7
13.9 11.4
52.0 63.4
1 2
2.8 2.8
2.5 6.7
65.9 72.6
2 4
2.9 3.3
1.9 1.6
74.5 76.1
4 4
3.2 2.7
0.0 0.0
76.1 76.1
2 3 4 5 6 7 8 9
In both the experiments, there was continuous oil production through the first three cycles of injection. Skauge and Sorbie (2014) attributed this phenomena to gas finger diversion. The pressure drop across the core fluctuated continuously due to two reasons: in-situ oil displacement and gas breakthrough. There was
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no evidence of fines migration in the effluent samples from both the experiments. The CO2 reduced the viscosity of oil and reduced the pressure drop of the next brine injection slug. The relative permeability to brine was also enhanced as a result of the reduced oil viscosity (Aleidan and Mamora 2010). Ramanathan et al. (2015) reported final oil recovery values of 61.7% and 64.6% from low-salinity brine-alternating-CO2 injection (Experiment A-5) and seawater brine-alternating-CO2 injection (Experiment A-6) in unaged cores, respectively. In comparison to the previously conducted experiments, aged cores yielded more oil. Low-salinity brine-alternating-CO2 injection recovered 36% more oil when an aged core was used. Contact angle measurements of aged cores proved that there is a definite case of wettability alteration towards a more water-wet state when low-salinity brine was used instead of formation brine. This is the reason for the incremental oil recovery in aged cores during the low-salinity WACO2 injection. Seawater brine-alternating-CO2 injection yielded 11.5% more oil when an aged core was used in the coreflooding experiments. The rock achieved an intermediate-wet state during the contact angle measurements done in this work. The incremental oil recovery is attributed to the change in the wetting state of the rock. Computerized Tomography (CT) Scanning This section deals with the development of porosity and saturation profiles using the CT scanning method. The cores that were characterized in this study include: RSR 25, RSR 30, RSR 20, and RSR 22. The latter two cores were used in coreflooding experiments for a WACO2 study conducted by Ramanathan et al. (2015). Figs. 8 through 11 represent the CT number data for RSR 20, RSR 22, RSR 25, and RSR 30, respectively. Each plot demonstrates the change in the CT number across the length of the core in its various saturation states: dry core, 100% water saturated core, oil saturated core with an irreducible water saturation, and the residual oil saturated core. The CT number curves were similar for all the cores. However, there was a difference in the absolute values of the CT number for each core, indicating different properties and saturations. Table 7 presents the average porosity for each core derived from the CT numbers. Figs. 12 and 13 presents the porosity distribution across the length of the core. These derived porosity values are in strong agreement with the experimental numbers.
Figure 8 —CT number profile of RSR 20 at its different saturation states.
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Figure 9 —CT number profile of RSR 22 at its different saturation states.
Figure 10 —CT number profile of RSR 25 at its different saturation states.
Figure 11—CT number profile of RSR 30 at its different saturation states.
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Figure 12—Porosity distribution profile for the unaged cores RSR 20 and RSR 22.
Figure 13—Porosity distribution profile for the aged cores RSR 25 and RSR 30. Table 7—Average porosity calculations from the CT scans. Core ID RSR RSR RSR RSR
20 22 25 30
Average Porosity from CT Scan 17.35% 18.94% 18.73% 17.60%
The density of the fluids in the core determine the CT-numbers. The CT-number values of air, oil, and formation brine are ⫺1,000, ⫺121, and 244. The CT-numbers of the dry core is lower than the others because it only contains air. Since water has the highest density, the water saturated oil has the highest CT-numbers as well. Oil has a lower density than water and it is illustrated by the lower CT-number than the water saturated core. The core after the WAG experiment contains mainly water and some trapped CO2. This is the reason for the lower CT-number profile of the final core relative to the oil-saturated core.
SPE-179674-MS
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Conclusions Coreflood experiments determined the oil recovery and pressure drop in aged cores during the WACO2 injection. Furthermore, the effect of brine salinity on the interfacial tension was evaluated as well. Contact angle measurements established the wettability of the rock in aged systems. The aging of the rock greatly changed the rock wettability and the oil recovery. The following conclusions stem from the results obtained: 1. Aging the rock produced more oil during the WACO2 injection. Low-salinity brine-alternatingCO2 produced 36% more oil when an aged rock was used. Seawater brine-alternating-CO2 improved its oil recovery by 11.5% when an aged core was used. 2. Contact angle measurements of the rock/brine/oil/CO2 system showed that rock aging increases the contact angle of the rock. The change in wettability was a reason for the improved oil recovery during the WACO2 experiments. 3. Interfacial tension measurements of the oil/brine/nitrogen and oil/brine/CO2 systems showed that the salinity of the brine has an effect on the IFT. Low-salinity brine produced the highest IFT, whereas seawater brine gave the least.
Acknowledgments The authors would like to recognize Ms. Gia Alexander for proofreading this paper.
Acronyms ADSA CT DSA HP/HT IFT OOIP ppm SEM Soi TDS WACO2 XRD XRF
⫽ ⫽ ⫽ ⫽ ⫽ ⫽ ⫽ ⫽ ⫽ ⫽ ⫽ ⫽ ⫽
axisymmetric drop shape analysis computerized tomography drop shape analyzer high pressure/high temperature interfacial tension original oil in place parts per million scanning electron microscope initial oil saturation total dissolved solids water-alternating-CO2 X-ray powder diffraction X-ray fluorescence
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