Assessing the feasibility of improving the performance of CO2 and

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Assessing the feasibility of improving the performance of CO2 and CO2-WAG injection scenarios by CWI Mojtaba Seyyedi, and Mehran Sohrabi Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.8b02000 • Publication Date (Web): 30 Jul 2018 Downloaded from http://pubs.acs.org on July 31, 2018

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Industrial & Engineering Chemistry Research

Assessing the feasibility of improving the performance of CO2 and CO2-WAG injection scenarios by CWI Mojtaba Seyyedi1,2,*, Mehran Sohrabi2

1 Chemical and Petroleum Engineering Department, University of Calgary, Calgary, Alberta, Canada. 2 Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, United Kingdom

Abstract In water-wet systems, the oil recovery performance of CO2 and CO2-WAG injection scenarios is negatively affected when the injection pressure is below the minimum miscibility pressure and the spreading coefficient is negative. Under these conditions, the bypassed oil in the porous medium will have the minimum surface contact area with the injected CO2. Thus, injection strategies that can improve this contact can enhance the CO2 performance. This study aims to quantify the impacts of injecting carbonated water (CW) prior to CO2 injection on oil recovery by CO2 and CO2-WAG injection scenarios. For this aim, a series of integrated high-pressure and high-temperature coreflood, micromodel and IFT experiments were performed using live crude oil. Coreflooding tests indicate that the pre-flush of CW improved the sweep efficiency of CO2 injection by 6.6 % of the original oil in place. According to micromodel experiments performed under the condition of coreflood tests, during CWI period, CO2 partitioning from CW into the remained oil led to oil swelling, which in turn led to an increase in the remained oil saturation. Oil swelling also led to rupturing of the water layers shielded isolated oil ganglions and thus reconnection of isolated oil ganglions. Due to these changes, more oil will be accessible to the CO2 stream which in turn can favour the CO2 recovery performance. More importantly, IFT experiments showed that the pre-flush of CW impacts the interfacial tensions between the fluids (oil-water-CO2) and the spreading coefficient. Pre-flush of CW shifted the spreading coefficient from a negative value to a positive value. In a water-wet system, this shift maximises the oil spreading or surface contact area between the CO2 and oil, and consequently favours the oil recovery performance of CO2 injection. Keywords CO2; WAG; Carbonated water injection; new gaseous phase; spreading coefficient 1. Introduction CO2 and CO2-WAG injection scenarios are usually conducted after conventional waterflooding (WF) period to recover some parts of the remaining oil in the reservoirs1–8. The performance of these Enhanced Oil Recovery (EOR) scenarios is a function of a series of interlinked parameters, such as the

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injection pressure, wettability state of the reservoirs, and spreading coefficient9–15. If the injection pressure is above the minimum miscibility pressure (MMP), the miscibility between the oil phase and CO2 stream would occur which will significantly improve the oil recovery performance of CO2 injection. However, if the injection pressure is below the MMP, the miscibility would not take place and oil swelling and oil viscosity reduction due to CO2 diffusion into the oil will be the main oil recovery mechanisms11,12. Furthermore, wettability and spreading coefficient (SC) are two prominent parameters controlling the microscopic and macroscopic displacement efficiencies of immiscible CO2 injection13,14,16–21. Spreading coefficient (SC) implies the imbalance of the fluids interfacial tensions acting along the contact line between the phases19. The spreading coefficient can be either positive or negative and for the water-oil-gas system, it is defined as: = − −

Where is gas-water surface tension, is the gas-oil interfacial tension, and is the water-oil interfacial tension. The value of spreading coefficient determines the fluids (oil-CO2-water) distributions in the pores and therefore it directly affects the oil recovery during CO2 injection. It should be noted that the impact of this value must be considered in couple with the wettability of the porous medium. As presented by several researchers13,14,19–21 for the case of water-wet systems, a positive spreading coefficient implies the oil tendency on spreading as a film between the gas and water, while a negative value indicates oil lenses floating in the gas-water interface. As a result, for the case of water-wet systems, the maximum spreading of the oil happens when the spreading coefficient value is positive. Based on these studies, for the case of oil-wet systems, if the spreading coefficient is positive, it signifies that oil tends to isolate the gas and water from each other by spreading between them, while a negative spreading coefficient indicates that both gas and water phases flow as separate drops entrained in the oil phase. Consequently, for the case of oil-wet systems, maximum oil spreading, or in other words maximum contact between gas and oil, happens when the spreading coefficient value is negative. Oren and Pinczewski13,14 indicated that in an oil-wet system, the oil recovery by gas flooding was better when the value of spreading coefficient was negative; conversely, for the water-wet system, an opposite trend was observed. Therefore, for water-wet systems, when the spreading coefficient is negative, and the injection pressure is below the MMP, a low performance of CO2 injection is expected. For such systems, injection strategies, which can increase the surface contact area between the trapped oil and CO2 in the porous medium, can improve the oil recovery performance of CO2 injection. This study aims to assess the feasibility of improving the performance of CO2 and CO2-WAG injection scenarios by injecting CO2-enriched water (CW) into the reservoir prior to CO2 injection. 2 ACS Paragon Plus Environment

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Shu et al22 studied the impacts of carbonated water injection (CWI) prior to CO2 flooding on the performance of CO2 injection in water-wet sandstone cores. Their results indicated that injection of CW prior to CO2 injection led to the better performance of CO2 injection by 12.2 % of the original oil in place. In their study, the details of mechanisms that contributed to this additional oil recovery were not discussed and dead crude oil was used. The majority of the oil reservoirs have live oil (oil with dissolved gases) rather than dead oil. Currently, the important role of the presence of associated gas in oil on the oil recovery mechanisms of CWI was indicated23–28. Through a batch of high-pressure and high-temperature coreflood, micromodel and PVT experiments23–28, it was shown that CO2 partitioning between CW and live crude oil leads to the rapid formation and continues growth of a new gaseous phase inside the oil phase. It was shown that the new gaseous phase plays an important role in oil recovery by CWI under realistic reservoir conditions. Therefore, to have a better understanding of the actual influences of the pre-flush of CW on the performance of CO2 and CO2-WAG injection strategies in water-wet systems, using live oil is recommended. With this objective, a series of high-pressure coreflood, micromodel and IFT experiments were performed using a live crude oil. 2.

Experimental Setups and Procedure

2.1. Core Flood Rig Figure 1 presents the schematic of utilized flooding facility. The rig is equipped with Hastelloy type injection cylinders, a Hastelloy type coreholder, a back-pressure regulator, two differential pressure transmitters, three injection pumps, a separator, a gasometer and a data acquisition system. All the equipment were housed inside an oven working at the constant temperature of 100 °F. The rig can work under high-pressure and high-temperature conditions using any type of fluid. To avoid the corrosion by CO2 and high-salinity brine, all the wetting parts of the rig were made of Hastelloy.

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Figure 1: Schematic of the flooding rig 2.2.

Fluids Properties

Stock tank crude oil A with the density of 0.9286 gr/cm3 was used. Figure 2 presents other properties of this crude oil. To prepare the live crude oil, crude A was fully saturated with CH4 at the pressure of 2450 psi and temperature of 100 °F. A synthetic high salinity sea brine with the ionic composition shown in Table 1 was used. To make the carbonated brine, highly pure CO2, with the purity of 99.99 mol%, was mixed with the brine at the pressure of 2450 psi and temperature of 100 °F. The saturation pressures of both CW and live crude oil were 50 psi lower than the test pressure to exclude any possible CO2/CH4 exsolution due to possible pressure variations.

Table 1: Sea brine Components

Ion +

Na Ca+2 Mg+2 SO4-2 ClHCO3-1

ppm 16844 664 2279 3560 31107 193

Figure 2: Crude A properties


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2.3.

Core Properties

A homogenous sandstone core was drilled from an outcrop. The dimensions and physical properties of the core are shown in Table 2. Figure 3 shows the EDS map of a slice of the utilized rock. The rock is mainly made of silica oxide (Quartz). Figure 4 shows the wettability state of a slice of the cleaned outcrop sandstone core in the presence of crude A and sea brine shown in Table 1. The contact angle measurement, which was performed at 2500 psi and 100 °F, showed that the wettability state of cleaned sandstone core is water-wet. Table 2: Dimensions and properties of the core used in this study

Length (cm)

Diameter (cm)

Porosity%

Absolute K (mD)

Pore Volume (cc)

14.8

3.8

23.68

142

39.6

Figure 3: EDS map of the used sandstone rock.

Figure 4: Original wettability state of the cleaned sandstone rock is water-wet.



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2.4. Methodology First, the core was cleaned by injecting consequently toluene and methanol under high pressure and high-temperature conditions. Then, its pore volume, porosity and permeability to the sea brine (Table 1) were measured. Next, through a drainage process of the brine-saturated core with the live crude oil (i.e., displacement of brine with crude oil), the initial water saturation (Swi) was established. Having established the initial water saturation, the core was used for the experiment. The whole process of establishing the initial water saturation was less than few hours. Therefore, the contact time between the water-wet core and the crude oil was negligible. Thus, it is assumed that core wettability remained intact and water-wet. To be sure that such a short contact time between the crude oil and the water-wet sandstone core did not alter the core wettability state, a droplet of crude oil A was placed on a slice of the rock, which was submerged in the sea brine, and variations in the contact angle were monitored over 25 hours at 2500 psi and 100 °F. The results are shown in Figure 5. Figure 5 shows that the increase in contact angle is very small and negligible. Even after 25 hours contact between the crude oil droplet and sandstone rock, the system is water-wet. Thus, our assumption about the core being yet water-wet after establishing the initial water saturation is valid.

Figure 5: Change in the contact angle of crude A-sandstone rock-sea brine system over 25 hours. In experiment number one, after conventional waterflooding, the core was flooded by one pore volume of CO2 followed by an extended WF period. To study the impacts of pre-flushing carbonated water (CW) on the performance of CO2 injection, in the second coreflood experiment, after WF and prior to CO2 injection, the core was flooded by one pore volume of CW; next it was flooded by one pore volume of CO2 followed by an extended CWI. Table 3 summarizes the experiments and their conditions. Both experiments were performed at pressure and temperature of 2500 psi and 100 °F


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with an injection rate of 5 cm3/hr. CO2 was not miscible with the used crude oil under the experimental conditions of this study. Table 3: Summary of the coreflood experiments

Exp. 1 2

Injection Strategy

WF

WF CO2 Inj Extended WF 1 PV CWI CO2 Inj. Extended CWI

Pressure psia

Temperature °F

2500 2500

100 100

3. Experimental Results Figure 6 presents the recovery factor (RF) versus pore volume of injection (PVI) during the conventional waterflooding periods in both experiments. Both experiments presented the same behavior during the waterflooding period. In both experiments, the water breakthrough (BT) happened at around 0.46 PVI followed by the slight amount of oil production. At the end piece of the core, capillary pressure vanishes which yields to the accumulation of the wetting phase at the sample end29. This phenomenon is called capillary end effect. One way to produce that wetting phase is bump flooding. To overcome the capillary end effect, both cores were flooded with two higher rates, 25 cm3/hr and 50 cm3/hr. However, no oil was produced during the bump flood period, which could indicate, in both experiments, oil was not the wetting phase. Conventional waterflooding in both experiments led to the production of 61.46 % of the original oil in place. Figure 7 presents the differential pressure (dP) across the core during both experiments. The observed jumps in dP are related to the bump flood periods.



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Figure 6: Oil recoveries in terms of %OOIP during waterflooding periods in both experiments.

Figure 7: Differential pressure across the core during waterflooding periods in each experiment.

Figures 8 and 9 present the impact of the pre-flush of CW on the oil recovery performance of CO2 injection. Figures 10 and 11 present the differential pressure behavior during the first and second experiment respectively. Comparison of the oil recovery curves of both experiments (Figures 8 and 9) indicates the better performance of CO2 injection when the core was flushed by CW prior to CO2 injection. In the first experiment, in which the pre-flush of CW was avoided, and CO2 was injected directly after waterflooding period, CO2 flooding led to an incremental oil recovery of 9.4 % of the original oil in place (OOIP). However, in the second experiment, pre-flush of CW improved the 8 ACS Paragon Plus Environment

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performance of CO2 injection and CO2 injection led to 16 % incremental oil recovery. The results present the positive impact of pre-flush of CW on the performance of CO2 injection. As indicated in Figure 8, no extra oil was recovered during the pre-flush of CW.

Start of Extended WF Start of CO2 Inj. Start of Extended CWI

Start of CWI

Start of CO2 Inj.

Figure 8: Oil Recoveries during both coreflood experiments with different injection strategies.

81

Ext. CWI Ext. WF

71

CO2

CO2

WF

WF

61

RF (%OOIP)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


51 41 31 21 11 1

Exp. 1

Exp.2

Figure 9: Oil Recoveries during flooding experiments with different injection strategies. 9 ACS Paragon Plus Environment


WF

CO2 Inj.

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Extended WF

Figure 10: Differential pressure across the core during first flooding experiment.

WF

CWI

CO2 Inj.

Extended CWI

Figure 11: Differential pressure across the core during second flooding experiment.

As seen from Figures 8 and 9, the oil recovery of the extended CWI performed after CO2 injection was around 3 % OOIP higher than that of extended WF after CO2 injection. To identify the reasons 10 ACS Paragon Plus Environment

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for this additional oil recovery, differential pressures across the core during the extended waterflood and CWI periods are compared in Figure 12. As indicated by Figures 8 and 12, although the amount of produced oil during the extended CWI period is two times higher than that of extended WF period, the rate of drop in dP during the extended CWI is less than that of extended WF. At the start of extended WF period, since the brine was displacing the supercritical CO2, which has less density (806.971 gr/cm3) and viscosity (0.07 cP) compared to the brine at experimental conditions, the dP across the core started to increase until it reached its maximum value at breakthrough of brine. At this stage, some parts of the bypassed CO2 remained in the rock as the residual gas. After water breakthrough, the dP started to drop sharply (orange curve in Figure 12). One of the reasons for the sharp drop in dP is the production of the bypassed CO2 phase through its dissolution into the injected brine (see Figure 13), which directly increased the brine relative permeability. The other reason for the sharp drop in dP during the extended WF period is the transfer of CO2 dissolved in the resided oil into the injected brine. During the extended WF period, water deprived the resided oil from the CO2 which was transferred into the oil during the CO2 flooding step. As a consequence, the oil shrank, which in turn led to the higher relative permeability of water, and therefore drop in dP. The orange curve in Figure 13 indicates the rate of CO2 production in experiment one, which confirms the production of some part of the trapped CO2 in the core during the extended waterflooding period. On the other hand, since CW was already saturated with CO2, it did not have any tendency for dissolving the trapped CO2 phase in the porous medium. Therefore, after CW breakthrough, the bypassed CO2 remained in the porous medium as a trapped gas phase, which in turn led to the redistribution of fluids through diverting CW into the unswept areas of the porous media and thereby additional oil recovery.



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Figure 12: Differential pressure across the core during extended waterflood and CWI periods.

Figure 13: CO2 production rates during extended waterflood and CWI periods in both experiments.

4. Discussion Based on the flooding results performed at core scale, pre-flush of CW prior to CO2 injection improved the CO2 flooding performance by 6.6 % of the OOIP compared to the case in which the pre-flush of CW was avoided and CO2 flooding was started directly after conventional waterflooding. Since during both tests the experimental conditions and fluids were identical, and the only difference was the pre-flush of CW, the improvement in the oil recovery performance of CO2 injection can be attributed to the change in the fluids (oil-water-CO2) distributions and saturations inside the porous medium as a result of pre-flush of CW. In this section, this assumption is investigated. 4.1. Changes in Oil Saturation and Distribution As shown by flooding tests, no extra oil recovery was obtained during the pre-flush period of CW. However, this does not mean that the oil distribution inside the core during the CWI period did not change. A positive change in the oil distribution can make the oil more accessible to the CO2 stream, which in turn favours the oil recovery performance of CO2 injection. To study the feasibility of positive change in oil distribution during the pre-flush step of CW, a micromodel experiment under 12 ACS Paragon Plus Environment

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the conditions of coreflooding tests were designed and performed at 2500 psi and 100 °F. For this aim, a high-pressure and high-temperature micromodel rig was used. Micromodel rig will provide us a direct visualization of fluids distribution at pore-scale (micro-scale). More details about this rig can be found in our previous publications23,26. Like flooding tests, the micromodel was initially saturated with the sea brine, then the initial water saturation was established by injecting the live oil into the micromodel. Next, by injecting the brine into the micromodel, waterflooding step of the coreflooding tests was replicated. Having no further oil production, the waterflooding was stopped. Next, to replicate the CW pre-flush step of the second flooding test, the micromodel was flushed with CW from the same head as the brine was injected. During this step, by using a high-resolution digital camera connected to a computer, changes in the oil distribution and saturation were monitored. Figure 14 presents changes in the oil distribution in a magnified section of the micromodel during CWI step. Figure 14A was captured at the end of waterflooding step and Figure 14B was captured after two hours of CWI. As seen from Figure 14A, the residual oil ganglions are disconnected from each other and are shielded by water layers which cause CO2 cannot directly contact all the residual oil. This phenomenon is called water blockage or water shielding effect30,31. In this case, if the oil swelling due to the diffusion of CO2 from the water barrier into the oil is enough to rupture the water layer, the trapped oil will be produced otherwise the trapped oil will remain in the reservoir as an unrecoverable phase. As shown in Figure 14B, although the bypassed oil was not produced during CWI period, its saturation increased. The extent of increase in oil saturation is shown in Figure 15. The increase in oil saturation is due to the strong CO2 partitioning from CW into the oil phase which in turn leads to the formation and growth of the new gaseous phase and oil swelling. Because of the strong oil swelling, the water layers, which surrounded the isolated oil ganglions, were ruptured and water-shielded oil bubbles connected to each other. The overall impacts of residual oil swelling (or increase in residual oil saturation), rupturing of water layers shielded isolated oil ganglions, and reconnection of isolated oil ganglions will increase the surface contact area between the CO2 and trapped oil (i.e. favour the oil accessibility to the CO2 stream) and thus improve CO2 oil recovery performance.



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Direction of flow A

B

Figure 14: A magnified section of the micromodel after A. conventional waterflooding and B. two hr of CWI. CO2 partitioning from CW (shown in blue colour) into the oil (shown in brown colour) led to the formation of the new gaseous phase (shown in white colour) and strong oil swelling which in turn leads to an increase in residual oil saturation and oil reconnection.

CWI

Figure 15: Increase in oil saturation (Soil) due to CO2 transfer from CW into bypassed oil ganglions.

4.2.

Change in the Spreading Coefficient

Pre-flush of CW may impact the interfacial tensions between the fluids (CO2-brine-oil), which consequently affects the oil-brine-CO2 distribution during CO2 injection. To study this possibility, the values of spreading coefficients for the binary systems of brine-oil-CO2 and CW-oil-CO2 were measured and compared. For this aim, the IFT measurement rig equipped with the axisymmetric drop shape analysis (ADSA) technique was used. Details of this rig can be found in our previous publication32. Figure 16 shows the schematic of the IFT measurement rig. Each IFT measurement was 14 ACS Paragon Plus Environment

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performed under the conditions of the flooding experiments (2500 psi and 100 °F) and repeated by at least three times and their average values were reported. The measured IFT values plus the spreading coefficient values of both systems; i.e. brine-oil-CO2 and CW-oil-CO2, are presented in Table 4. The value of spreading coefficient for CW-oil-CO2 system is positive while it is negative for brine-oil-CO2 system. This is due to the lower interfacial tension between CW-oil compared to the brine-oil. Transfer of CO2 from CW into the oil led to the reduction of the interfacial tension (IFT) between the oil and CW. The IFT reduction by CWI was also reported by other researchers33,34. Since, during coreflooding tests, the wettability state of the core was water-wet, change in the spreading coefficient from negative to positive by pre-flush of CW positively influenced the fluids distributions inside the core and thus favored the oil recovery during CO2 injection period. Figure 17 shows the change in fluids distribution because of change in spreading coefficient.

Figure 16: IFT measurement rig Table 4: Measured IFT and spreading coefficient values for both systems System

SC

Brine-Oil-CO2

23.8

1.12

28

-5.32

CW-Oil-CO2

23.7

1.12

18

4.58



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Figure 17: Change in the spreading coefficient of a water-wet system due to pre-flush of CW.

5. Conclusion The results of this study indicated the positive impact of pre-flush of CW on the oil recovery performance of CO2 and CO2-WAG injection scenarios in water-wet systems. Based on the flooding results, the performance of CO2 injection was increased by 6.6 % of the original oil in place when the porous medium was flushed by CW prior to CO2 flooding. According to the micromodel and IFT experiments performed under the conditions of flooding tests, the pre-flush of CW leads to a favourable change in the fluids distribution and saturation inside the porous medium. As a result of pre-flush of CW and CO2 mass transfer from CW into the residual oil, oil swelling takes place which in turn leads to rupturing of the water layers shielded isolated oil ganglions, reconnection of isolated oil ganglions, and an increase in bypassed oil saturation. Therefore, more oil will be accessible to the CO2 stream which in turn favours the oil recovery potential of CO2 injection. Furthermore, pre-flush of CW affects the interfacial tension between the oil-water phases, thus it impacts the spreading coefficient. For the system used in this study, pre-flush of CW changed the spreading coefficient value from negative to positive. This change leads to the maximum oil spreading, or in other words maximum contact between oil and CO2, which in turn favours the CO2 performance. Acknowledgement This work was carried out as part of the ongoing Enhanced Oil Recovery by Carbonated Water Injection (CWI) joint industry project (JIP) in the Institute of Petroleum Engineering of Heriot-Watt University. The project is equally sponsored by ADCO, BG Group, Eni, Galp Energia, Oil India, and the UK DECC, which is gratefully acknowledged. References (1)

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Assessing the feasibility of improving the performance of CO2 and

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