Viscous Oil Recovery and In-situ Deasphalting in Fractured Reservoirs

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Cite This: Energy Fuels XXXX, XXX, XXX−XXX

Viscous Oil Recovery and In Situ Deasphalting in Fractured Reservoirs: Part 1. The Effect of Solvent Injection Rate Chao-Yu Sie,† Bradley Nguyen,† Marco Verlaan,‡ Orlando Castellanos-Diaz,‡ Kelli Adiaheno,† and Quoc P. Nguyen*,† †

Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, 200 East Dean Keeton Street, Stop C0300, Austin, Texas 78712, United States ‡ Shell Canada Ltd., P.O. Box 100, STN M, Calgary, Alberta T2P 2H5, Canada ABSTRACT: Steam-based EOR methods for viscous oil recovery from fractured reservoirs have significant challenges in both cost and energy efficiency. In response, solvent-based methods have been of interest because of their low energy intensity, low greenhouse gas emissions, and no fresh water consumption. Injection strategies for viscous oil recovery by solvent include liquid extraction and vapor oil gravity drainage. Understanding the mechanisms in each phase is of great value for the successful application and optimization of solvent EOR processes. The work presented here studies the effect of solvent injection rate on viscous oil recovery by liquid extraction with n-butane in vertically placed sandstone cores with an artificial fracture. The oil production rate, ultimate recovery, and in situ deasphalting in different sections of the core are analyzed. The oil production rate increased with solvent injection rate until it leveled off as the injection rate exceeded a critical value. The ultimate recovery factor is nearly the same for all solvent injection rates below the critical value. However, it is significantly reduced at higher injection rates. A conceptual model based on convective mass transfer is proposed and the effect of mechanical dispersion is discussed. In situ deasphalting was observed in all cases. The cause of the unexpected changes in production rate was attributed to severe asphaltene deposition and remobilization in the fractured permeable rock. In such a medium, solvent injection rate seems to show an optimal value for maximizing oil production rate, ultimate recovery factor, and solvent efficiency.

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INTRODUCTION Recently, there has been growing interest in unconventional hydrocarbon formations because of the depletion of conventional oil reserves. Although the cost of drilling and hydraulic fracturing has been decreased in the past decade, research on viscous oil production still received great attention because heavy oil and bitumen consists of a c.a. 60% of unconventional oil. It was reported that global reserves of viscous oil are estimated to be at least one trillion tons.1 Recovery of viscous oil from naturally fractured reservoirs (NFR) has been a challenging problem because of the significant difference in permeability between fractures and matrixes. Miscible and immiscible gas injection have been extensively studied for oil recovery from NFR.2−5 However, low production efficiency is expected if the process is applied in extra heavy oil or bitumen recovery due to high oil viscosity, unfavorable oil wetness, and low matrix permeability.6 Previous studies have shown that the production rate and ultimate recovery are still low even if gas-oil gravity drainage (GOGD) is thermally enhanced.7,8 Steam-assisted gravity drainage (SAGD), a technology widely applied for bitumen recovery in sandstone reservoirs in Canada, also poses significant challenges. A recent pilot test in the Grosmont formation in Alberta, a fractured carbonate reservoir with over 400 billion bbl of bitumen resources, showed that conventional SAGDtype injection may not be an optimal strategy for bitumen recovery from fractured reservoirs.9,10 Solvent-based processes have proven to be a promising alternative in bitumen recovery from fractured reservoir because they are less energy intensive, require less fresh © XXXX American Chemical Society

water, and produce less greenhouse gas when compared with steam-based processes. Edmunds et al.11 performed a laboratory core soaking experiment with an 80 cm long preserved core in which a noncondensable carrier gas was saturated with propane to keep the mixture at dew-point. More than 60% of bitumen in place was recovered, indicating the potential of solvent extraction as a large-scale, low-cost nonthermal bitumen recovery method for the Grosmont reservoir. Jiang et al.12 conducted warm and cold vapor solvent soaking experiments in cores taken from the Grosmont formation. The results showed that the solvent-based gravity drainage process has high recovery potential in fractured bitumen reservoir. They also concluded that warm solvent soaking is more favorable in comparison to cold solvent soaking because of higher mass diffusivity between solvent and bitumen at higher temperature. Pathak et al.13,14 performed propane and butane soaking experiments with glass beads, Berea cores and full-sized preserved Grosmont cores. The experiments showed that the dilution of bitumen is better and the asphaltene content of the produced oil is lower when butane was used in the experiment. They concluded that the temperature and pressure of the system are two key parameters in determining the ultimate recovery factor. The highest recovery factor was achieved when the temperature and the pressure of vapor solvent were kept near the saturation line. Leyva-Gomez and Babadagli15 studied bitumen recovery by Received: November 1, 2017 Revised: December 12, 2017 Published: December 12, 2017 A

DOI: 10.1021/acs.energyfuels.7b03375 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels liquid n-heptane injection in oil-wet and water-wet sandstone cores with a single fracture. Solvent was injected into horizontally placed fractured cores with the rates from 0.1 to 2 mL/min. The results showed that a lower injection rate leads to higher solvent efficiency (i.e., ratio of cumulative bitumen produced to cumulative solvent injected) in their system because the residence time of the solvent is higher when the injection rate is lower. To study the effect of temperature on oil recovery, we conducted additional experiments at different temperatures with a constant injection rate and back pressure. Higher ultimate recovery factors were observed when the operating temperature was closer to the saturation temperature of the solvent, which is consistent with the results in the static soaking experiments mentioned above.13,14 The combination of solvent and steam (or hot water) injection has also been studied extensively. Bryan et al.16 conducted a four-step soaking experiment on a fractured Grosmont carbonate core saturated with bitumen. The process is followed by 200 °C steam soaking, 200 °C steam/propane mixture soaking, 200 °C propane soaking, and 46 °C propane soaking. The results showed low temperature solvent soaking is the most effective recovery process. They claimed that viscosity reduction of propane-oil mixtures determined by temperature and solubility of propane in bitumen is the key parameter of oil production in passive soaking experiment, and the dilution of bitumen is more important than temperature effect in viscosity reduction. Little incremental recovery was observed in the third stage because the solubility of propane in bitumen at 200 °C is quite low at the operating pressures used. The solubility of propane in bitumen at constant pressure increases greatly at 46 °C compared to that at 200 °C, which leads to a significant reduction in the viscosity of the propane-oil mixture. Thus, a 50% incremental recovery was observed at the fourth step. AlBahlani and Babadagli17 proposed a new process named “Steam-Over-Solvent in Fractured Reservoir” (SOS-FR) which consists of three phases: steam or hot water preheating, solvent injection, and solvent retrieval by steam reinjection. Static experiments were conducted by soaking Berea sandstone plugs and carbonate cores in hot water and different solvents, and dynamic experiments were performed by injecting hot water and heptane alternatively into fractured sandstone cores.18 Higher recovery factor and asphaltene precipitation were observed when lighter hydrocarbons were applied in the static experiment. Dynamic experiments showed that an optimal injection rate with highest oil recovery rate and lowest solventoil ratio exists. Mohammed and Babadagli19 conducted static soaking experiments with the addition of chemicals in the hot water soaking phase, and the results indicated that the wettability alteration by soaking the cores in hot water with chemicals is critical for additional oil recovery. As can be seen, most studies have concentrated on static solvent/steam soaking; oil recovery mechanisms during continuous solvent injection and the effect of in situ deasphalting were rarely examined and discussed in the aforementioned studies. Rankin et al.20 conducted preliminary proof-of-concept experiments on viscous oil recovery in a sand pack simulating a single-fracture matrix system. The novel warm solvent injection strategy that combines two mechanisms, liquid extraction and vapor solvent-oil gravity drainage, showed high oil production rate and low residual oil saturation. In this process, injected warm solvent is initially in vapor phase but subsequently condensed by the initially lower formation temperature. Liquid extraction occurs before the system is

heated above the vapor pressure of solvent. After the system has reached the target operating temperature, the injected solvent becomes vapor and the production mechanism is dominated by film gravity drainage. In this work, we seek to extend the study from Rankin et al.20 through investigating the effect of solvent rate on the mechanism of liquid solvent extraction and the dynamics of deasphalting in a single fracture-matrix system. Instead of sand packs,20 cores drilled from a well consolidated sandstone outcrop are used for a more realistic matrix permeability and pore network morphology. The core flood experiments are conducted at a constant temperature and production pressure such that the injected solvent (n-butane) remains in liquid phase. In-situ deasphalting in each core flood is examined based on the analysis of residual and effluent oil. n-Butane was chosen in this work because of the following reasons: (i) nbutane fits condensing conditions at low temperatures, (ii) nbutane is cheap and hence an economical fluid, (iii) successful pilot has been performed in Canada.

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METHODOLOGY

The bitumen is a dewatered/degassed sample provided by Shell Canada. The viscosity profile of bitumen at different temperature is shown in Figure 1. n-Butane is supplied as research grade (99.99%

Figure 1. Viscosity profile of bitumen used in experiments fit with modified Walther equation.21 purity) by Airgas. For asphaltene content analysis, toluene is research grade (99.5%) from Fisher Scientific, and n-heptane is research grade (99.0%) from Acros Organic. Experiments were performed using Idaho Gray sandstone cores all drilled from the same block. The permeability of each core was estimated by measuring the permeability of a representative core plug drilled from the same block with 3 wt % sodium chloride solution. The porosity of each core was measured by the volume of bitumen injected during the oil saturation process. The experimental setup (Figure 2) with adjustable temperature, pressure, and solvent injection rates was designed to investigate the mechanisms of bitumen recovery when liquid solvent was injected into a bitumen-saturated core with an artificial fracture. The experiments consisted of three stages: core preparation, solvent injection, and asphaltene analysis. Core Preparation. Core preparation process is schematically illustrated in Figure 3. Two Idaho Gray cores, two inches in diameter and 12 inches in length, were split axially. Four semicylindrical cores B


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Figure 2. Experimental apparatus.

Figure 3. Illustration of core preparation process: (a) Four semicylindrical cores. (b) Combined core with a rubber sheet (24 in. × 2 in. × 0.04 in.) between the cut plane. (c) Oil-saturated core with two Teflon strips (24 in. × 0.375 in. × 0.04 in.) between the cut plane. were dried in an oven at 150 °C for 48 h to remove the residual water. Four cores were combined with a 24 in. × 2 in. × 0.04 in. rubber sheet in the middle of axially cut plane in order to prevent the early breakthrough of bitumen during the saturation process. The combined core was loaded to the custom-designed core holder (1) in the oven, and the overburden pressure was applied (3.55 MPa axially and 6.99 MPa radially). The inlet of the core holder contained a flow distributor, which ensured that the entire core inlet area was exposed to the injected fluid. The oven was heated to 50 °C and the core saturated with oil under vacuum. Because of the high viscosity of bitumen at room temperature, the oil saturation process was conducted at 50 °C to increase the bitumen mobility. Bitumen in oil accumulator (2) was displaced by Quizix Precision Pump (3) during the saturation process. After two pore volumes of bitumen were injected, the injection was stopped and the system was cooled to the ambient temperature. Once oil saturation had been completed, the combined core was removed from the core holder. Four oil-saturated semicylindrical cores were separated to remove the rubber plate, and were combined axially again with two 24 in. × 0.375 in. × 0.04 in. Teflon strips attached to the edge of cores between the cut plane. The combined

core is designed to simulate the bitumen recovery process in a singlefracture matrix. The length of the combined core was chosen to reduce the capillary end effect.22 The saturated, 24 in. long core with a 0.04 in. width artificial fracture was loaded into core holder (1) and the same overburden pressure was applied. Three wt % sodium chloride solution was injected bottom-top with the outlet valve of the core holder opened. Because of the high viscosity of bitumen at room temperature and the high matrix/fracture permeability contrast, the brine was injected through the fracture without displacing the bitumen. The brine volume that remained in the fracture was used to calculate the fracture width. It was found that the calculated fracture width was very consistent with the initial fracture width (0.04 in.). The fracture permeability (k), which was estimated using the fracture width and eq 1,23 is about 84403.7 Darcy. k=

b2 12

(1)

where b is the width of the fracture. The oven was then heated to the target temperature (50 °C) before solvent injection. The amount of thermally expanded oil in each case C


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Energy & Fuels was recorded and was not included in the calculation on recovery profile and ultimate recovery factor. Solvent Injection. n-Butane was compressed into the liquid phase by a Haskel AGT-4 compressor into the 3 L piston-type accumulator (4) to 1.83 MPa at room temperature. A Quizix Precision Pump (3) was applied to displace liquid solvent by distilled water. A backpressure regulator (5) with 1.83 MPa dome pressure was set at the outlet of the solvent accumulator (4) to maintain a constant injection rate and to prevent backflow of the solvent-oil mixture. The solvent flowed through a segment of coiled tubing immersed in the heated bath (6) to ensure the target temperature was achieved before being injected into the core. A J-type thermocouple from Omega Engineering was installed at the inlet of the core holder to monitor the temperature of the injected solvent. A backpressure regulator (7) was set at the outlet (bottom) of the core holder to control the pressure of the system. The structure of this backpressure regulator (7) was modified, and the material of the diaphragm was chosen specifically to handle the highly viscous bitumen flow and the deposition of asphaltene during the production. The pressure at the inlet and the outlet of the core holder was monitored by two Rosemount absolute pressure transmitters, and the pressure drop in the system was calculated from the difference between the inlet and outlet pressures. n-Butane was injected into the core top-down at a constant rate until no more bitumen was produced. The effluent collection system consisted of a double-walled glass heat exchanger (8), a heated bath (9), and a 250 mL cylindrical collector (10). The glass heat exchanger was kept at 80 °C using water heated by the heated bath (9). The temperature was chosen to ensure that the solvent had vaporized and separated from the produced bitumen. Produced oil was collected in a cylindrical collector. The vaporized solvent was passed through a wet test meter (11) to record the solvent production rate and was then vented to the fume hood. When bitumen was no longer produced, the oven was turned off, and the system was cooled for 24 h. After the system had reached room temperature, the overburden pressure was released, and the core was removed from the core holder. Asphaltene Analysis. The core was divided into four sections ID 1, 2, 3, and 4 from top to bottom. The amount of residual oil in mass in each section was determined using the following procedure. First, residual oil in each section was extracted with toluene using a Soxhlet extractor. Next, toluene from the final oil-toluene mixture collected from the Soxhlet process was removed by a rotary evaporator, and the mass of remaining oil (or residual oil) was measured. The heptaneasphaltene content in original bitumen, residual oil (after toluene removal) and effluent oil was determined by the modified ASTM method (ASTM D2007−80) proposed by Wang and Buckley.24

Figure 4. Oil recovery versus time for five different injection rates.

The pressure data from these five core floods will be introduced individually in this section and a more detailed discussion and comparison of the data will be shown in the following section. Case 1: n-Butane Injection Rate at 0.5 mL/min. Figure 5 shows the measured pressures at the inlet and the outlet of the core, the target outlet pressure in the experiment, and the saturation pressure of n-butane at 50 °C. n-Butane in the system was in the liquid phase during the bitumen recovery process as the inlet and outlet pressures were higher than the saturation pressure of n-butane. It took 70 min for the system pressure to build up to the target pressure (1.1 MPa), and oil breakthrough was observed after about 120 min (Figure 4). The oil production rate became stable at 0.22 mL/min after 160 min until the production reached a plateau. The ultimate recovery factor is 73%. n-Butane deasphalting occurred during bitumen production. Asphaltene deposits on the fracture planes are shown in Figure 6 (top). Gel-like, highly viscous asphaltene deposition (Figure 6, bottom) was also observed at the core outlet. The formation of such viscous asphaltene sludge would increase flow resistance in both fracture and matrix, and thus the pressure drop along the core at a fixed n-butane injection rate. Indeed, the frictional pressure drop over the entire core exerted by pure n-butane darcy flow at 0.5 mL/min in the fracture with an aperture of 1 mm is about 1 × 10−4 kPa, which is much smaller than the observed pressure drop (around 4.5 kPa, Figure 5). This discrepancy may be attributed to (i) the viscous flow of nbutane, bitumen, and asphaltene aggregates in the fracture, and (ii) the modification of the fracture aperture due to asphaltene deposition. Moreover, small asphaltene particles observed in the effluent oil could be responsible for the observed pressure fluctuation (Figure 5) because the backpressure regulator (BPR) used in this work was not suitable for suspension flow, and thus unable to precisely control the pressure of the effluent that contains a significant amount of solid particles. Case 2: n-Butane Injection Rate at 2 mL/min. The same core flood conditions for Case 1 were used in this case, except that the n-butane injection rate was increased by a factor of 4. The inlet, outlet and differential pressures for this case (Figure 7) fluctuated significantly as compared to those for Case 1. As the injection rate and the oil production rate increase, the velocity of asphaltene aggregates passing through the backpressure regulator (BPR) also increases. It is likely that the fast-flowing asphaltene aggregates and viscous bitumen sludge further reduce the ability of the BPR to control the flow

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RESULTS Core properties and injection rates used in the core flood experiments are shown in Table 1. All experiments were Table 1. List of Experiments and Core Properties case #

porosity (%)

permeability (Darcy)

.

1 2 3 4 5

32 31 31 31 31

2.3 2.7 2.7 2.4 2.4

0.5 2 4 6 10

conducted at 50 °C and 1.14 MPa core backpressure. Five different injection rates (0.5, 2, 4, 6, and 10 mL/min) were chosen to study the effect of the n-butane injection rate on bitumen recovery and in situ deasphalting. Figure 4 shows the oil recovery factor (defined as the ratio of the cumulative produced bitumen volume at a given point in time to the initial bitumen volume in the core) versus time for all injection rates. D


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Figure 5. Gauge and differential pressures during n-butane injection at 0.5 mL/min (Case 1).

Figure 6. Asphaltene deposition after n-butane injection: (top) asphaltene deposition on fracture plane, (bottom) asphaltene deposition on the outlet plane (producer) of the core.

Figure 7. Gauge and differential pressures during n-butane injection at 2 mL/min (Case 2).

pressure. However, the system pressure still remained above the saturation pressure of n-butane, indicating the absence of butane vapor in the system throughout the experiment. Comparing Cases 1 and 2 shows that for an increase of injection rate by a factor of 4, the pressure drop increases from 4.5 to 12.2 kPa, whereas the oil production rate increased from

0.22 to 0.71 mL/min, and the time required to reach a plateau decreased from 1200 to 300 min (Figure 4). However, the same ultimate recovery factor (73%) were obtained for both core floods. Case 3: n-Butane Injection Rate at 4 mL/min. The nbutane injection rate was further increased to 4 mL/min in this E


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case. Figure 8 shows the pressures versus time during oil production. The prolonged fluctuation of differential pressure in Case 2 did not happen in Case 3 when the injection rate was doubled. The inlet and outlet pressures became stable after 25

min and remained lower than the target pressure by about 250 kPa. This may suggest that the BPR performance is steadier at higher flow rate for the specific type of effluent heterogeneity in our experiments. The average pressure drop for the injection F


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drains down through the matrix and the fracture. A pure liquid solvent zone (S) and a mixing zone (M) evolve during the extraction process (Figure 11). The viscosity of diluted

rate of 4 mL/min is about 6.4 kPa, which is lower than that for 2 mL/min (12.2 kPa in Case 2). The results indicate a significant reduction in flow resistance at an elevated injection rate. Such a decrease in pressure drop would not be responsible for the observed increase in the bitumen production rate by a factor of 2.3 (Figure 4) in terms of pressure drive. The oil recovery plateau in this case was reached after 150 min with 72% of initial oil in place recovered. The experiment was continued for another 300 min with only additional 1% recovery. Note that the bitumen production rate for Cases 1−3 increases with the injection rate, whereas the ultimate recovery factor remains almost unchanged. Case 4: n-Butane Injection Rate at 6 mL/min. A further increase of n-butane injection rate from 4 to 6 mL/min reduced the average pressure drop from 6.4 to 3.7 kPa (Figure 9), indicating an increase in fluid mobility with n-butane rate within the range from 2 to 6 mL/min. A sufficiently high flow rate may thus be necessary for improving the transport of asphaltene aggregates, particularly in the fracture. However, such improvement does not result in a further increase in bitumen production rate in this case. The initial production rate was about 1.67 mL/min, which is nearly the same as that for the n-butane rate of 4 mL/min (1.63 mL/min for Case 3). The production rate then decreased abruptly to 0.25 mL/min (at 68 min, Figure 4) before returning to its initial value (1.67 mL/min) at 213 min. The abrupt reduction in the production rate delayed the onset of production plateau by almost 210 min as compared to the production plateau for the n-butane rate of 4 mL/min. Moreover, the ultimate recovery factor (55%) was significantly reduced as the rate was increased to 6 mL/min. Case 5: n-Butane Injection Rate at 10 mL/min. To confirm that the abrupt change in bitumen production rate observed in Case 4 is typical for high n-butane injection rate, we used 10 mL/min as the highest rate in this work. The resulting pressure profiles and bitumen production profile are shown in Figure 10. The average pressure drop in this case is about 9.4 kPa, the second highest average pressure drop among all the five core floods (i.e., the highest is 12.2 kPa for the injection rate of 2 mL/min in Case 2). The abrupt reduction in the production rate was observed again at 82 and 228 min, which indicates that the effect of n-butane injection rate on the property and mobility of asphaltene aggregates is also rate dependent. An increase in solvent rate may accelerate asphaltene aggregation and deposition. The rapid formation of low mobility asphaltene aggregates at elevated solvent rate may inhibit mass transfer by virtue of decreasing solvent-bitumen contact, which could lead to an abrupt reduction in bitumen production rate as similarly observed for the two highest nbutane injection rates (i.e., production rate decreases from 1.67 to 0.25 mL/min for the injection rate of 6 mL/min, and from 1.60 to 0.32 mL/min for 10 mL/min, Figure 4). Even though the ultimate recovery factor for the injection rate of 10 mL/ min (67%) is higher than that of the case with the 6 mL/min injection rate (55%), it is still lower than that of all other lower injection rates (about 73%) where the change in bitumen production rate before the final production plateau is absent (Cases 1−3).

Figure 11. Schematic diagram of liquid extraction process: Pure liquid solvent (S) flows downward adjacent to the pure bitumen (B). Thin mixing zone (M) exists between two layers.

bitumen strongly depends on the solvent concentration profile in the mixing zone, which is controlled by three different mechanisms: (i) mutual diffusion between bitumen and solvent governed by component diffusivity and chemical potential within the mixing zone, (ii) convection and the associated mechanical dispersion which provide additional component mixing, and thus contribute to the dynamics of in situ component distribution, and (iii) in situ deasphalting which significant affects the physical properties of rock (i.e., permeability and porosity) and fluid (i.e., viscosity and molecular diffusivity). In the following sections, the effect of n-butane injection rate and deasphalting on bitumen production rate and ultimate recovery factor are discussed based on these three mechanisms and their interactions. Effect of Solvent Injection Rate. Figure 12 shows the average bitumen production rates of the cases with different nbutane injection rates. The production data before the abrupt reduction in production rate were used for calculating the average production rates for Cases 4 and 5 (Figure 4). It can be clearly observed from Figure 12 that the production rate increases as the injection rate increases from 0.5 to 4 mL/min, but remains nearly unchanged for higher rates (i.e., at and above 4 mL/min). Therefore, there exists a critical n-butane injection rate (between 2 to 4 mL/min), above which the bitumen production rate levels off at about 1.6 mL/min at 50 °C and 1.14 MPa. In our core flood experiments, the injected n-butane preferentially flows in the fracture due to the high permeability contrast between the fracture and the matrix, and thus the fracture surface area defines the initial n-butane-bitumen contact. The mixture of bitumen and n-butane in zone M (Figure 11) drains down mainly by gravity in time, allowing pure n-butane (zone S) to advance deeper into the matrix from the core entrance and the fracture. Because the entire core inlet area is exposed to the injected n-butane through a flow distributor, the local flow velocity in the matrix would increase

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DISCUSSION For the vertically fractured cores used in the series of core flood experiments described above, the bitumen is extracted by liquid n-butane and formed a bitumen-solvent mixture that G


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Figure 12. Respective average oil production rates for five different injection rates from 0.5 to 10 mL/min.

Figure 13. Boundary layer mass transfer as a simple conceptual model for the liquid solvent extraction process.

with the injection rate even in the presence of preferential flow in the fracture. An increase in local flow velocity reduces the thickness of the mixing zone (zone M, Figure 11). Therefore, higher solvent rate results in steeper concentration gradients in the mixing zone and higher mass transfer rate between the pure solvent and the undiluted bitumen. On the basis of the classical theory of mass transfer boundary layer,25 a simple conceptual model for the bitumen extraction process may be obtained to explain the effect of the n-butane injection rate observed in this work. Figure 13 depicts the mixing zone as a mass transfer boundary layer, in which the solvent flow is tangential to the pure bitumen surface in the absence of a porous medium. The diffusion flux of bitumen into the mixing zone (NB) may be expressed as NB = −DBS Sc1/3

Re =

uL υ

(3)

Sc =

υ DBS

(4)

where NB is the bitumen diffusion flux at the pure bitumen surface, DBS is the molecular diffusivity of bitumen in solvent, υ is the kinematic viscosity, CBS and CB0 are the respective bitumen concentrations at the undiluted bitumen surface and in the solvent stream, δC and L are the thickness and the length of the mixing zone, respectively. The two respective dimensionless groups are Schmidt number (Sc) and Reynolds number (Re). The former number shows the effect of transport properties (viscosity and diffusivity), whereas the latter number indicates the influence of fluid velocity on the mixing zone thickness (δC), and thus the diffusion flux (NB). u is the average fluid velocity, which is positively correlated to the solvent injection rate. According to eq 2, δC scales with u−1/2, the influence of the fluid velocity in zone M, Figure 11 (which

C − C B0 C − C B0 1/2 dC B ∼ DBS BS ∼ DBS BS Re δC dx L (2) H


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Figure 14. Recovery factor versus injected pore volumes at five different n-butane injection rates.

Table 2. Summary of Liquid-Solvent-Based EOR Experiments Conducted in Cores with an Artificial Fracture Sie et al.. (2017) (this work) T(°C) pressure (MPa) solvent oil viscosity at 25 °C (cP) rock type matrix porosity matrix permeability (mD) core radius (in.) core height (in.) oil rate(mL/min) solvent injection rate(mL/min) solvent efficiency(PV oil/PV solvent)

50 1.14 n-butane 90 000 sandstone 30% 2300 2 24 0.22 0.5 0.38

50 1.14 n-butane 90 000 sandstone 30% 2700 2 24 1.60 4 0.39

Trivedi and Babadagli (2008)31 15.6 0.1013 n-heptane 33.5 sandstone 20% 500 2 6 ∼5.0 × 10−2 0.1 0.6

15.6 0.1013 n-heptane 33.5 limestone 11% 15 2 6 ∼1.5 × 10−2 0.1 0.1

Leyva-Gomez and Babadagli (2016)15 21 0.1013 n-heptane 136 000 sandstone 21% 286 2 6 ∼3.0 × 10−2 2.0 0.015

45 0.1013 n-heptane 136 000 sandstone 21% 286 2 6 ∼5.0 × 10−2 0.1 0.33

130 0.1013 n-heptane 136 000 sandstone 21% 286 2 6 ∼0.10 0.1 0.32

in Figure 14. The volume of n-butane required to reach the recovery plateau are nearly the same for all subcritical injection rates (Cases 1−3). The average recovery factor is 0.39 per unit PV for the n-butane injection rate at or lower than 4 mL/min. However, the solvent efficiency decreases with increasing solvent rate above 4 mL/min. The result shown in Figure 14 is important for the economic evaluation of viscous oil recovery.30 It also emphasizes the impact of deasphalting on the solvent efficiency. Indeed, Figure 14 shows that the first reduction of recovery rate lasts for almost three injected pore volumes at 6 mL/min and even longer (four PVs) for the higher injection rate (10 mL/min) before the recovery rate returns to its initial values. In addition, asphaltene deposition is most likely responsible for the sharp plateaus of recovery factor and the unexpectedly low ultimate recovery factors that appear to correlate with the n-butane injection rate (Figure 14). The asphaltene effects are further elaborated in the following section. Table 2 compares the results from this work to other liquidsolvent-based flooding experiments conducted in cores with an artificial fracture. The oil production rate in our experiment is about an order of magnitude higher than that in other experiments, which may be attributed to the higher injection rates, matrix permeability, and matrix dimensions applied in this work. Despite the high injection rates, solvent efficiency

is correlated to the solvent rate) on the bitumen extraction is nonlinear and diminishes as the solvent rate increases. This statement is in agreement with the effect of the injection rate on bitumen production rate observed in our experiments (Figure 12). However, the boundary layer mass transfer in tightly confined porous and permeable media is complicated by the modification of molecular diffusivity and mechanical dispersion.26−28 The latter is mixing that occurs because of local variations in velocity around some mean velocity of flow. Dispersion that refers to both molecular diffusion and mechanical mixing influences the spreading of solvent concentration along the flow direction, and thus the chemical potential within the mixing zone. Moreover, dispersion is not uniform even in homogeneous porous media.29 Because the dispersion increases with flow velocity,27 the variation of component concentration within the solvent-bitumen mixing zone is reduced as the solvent rate increases, and thus modifies the diffusive mass transfer within the boundary layer according to eq 2. Unfortunately, it is not clear how much the mechanical dispersion contributes to the effect of solvent rate on bitumen production rate observed in our experiments. Moreover, the experimental results shown in Figure 12 call into question the efficiency of solvent in terms of recovery factor versus injected pore volume (PV) of n-butane as shown I


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Figure 15. Cumulative mass fraction of carbon number in the original bitumen and the effluent oil samples at five different n-butane injection rates.

(volume of produced oil over volume of cumulative solvent injected) in our cases is still comparative to that of other works. Because of high well injectivity in fractured reservoirs, our results indicate that injection strategy with a high solvent rate can be considered if severe formation damage by in situ deasphalting is not observed. In Situ Deasphalting. Asphaltenes are highly polarized, heteroatom components with condensed aromatic and naphthenic rings. When light hydrocarbon solvents (propane, n-butane, n-heptane, etc.) are in contact with bitumen, a phase partition occurs with the heavy phase being rich in asphaltene content. There are several potential advantages of in situ deasphalting including viscosity reduction and improved quality of produced bitumen by eliminating heavy metals, somewhat reducing sulfur content, prevention of catalyst deactivation in the upgrading and refining processes, and less coke formation.32,33 Figure 15 shows the cumulative mass fraction of carbon number in the original bitumen sample and the effluent oil samples from the five core floods. Note that the spike observed when the carbon number is 68 was confirmed to be a fluid analysis error. The effluent oil samples contain a higher concentration of low-carbon-number components compared to the original bitumen, indicating a reduction in heavy carbon number fractions at all n-butane injection rates. Heptaneasphaltene concentration and viscosity of the effluent oil samples at 50 °C for different injection rates are shown in Figure 16. Heptane-asphaltene concentration of original bitumen is 13.2 ± 0.5 wt %, and its viscosity at 50 °C is 3288.27 cP. A reduction of the asphaltene concentration by a factor of 3 decreases the bitumen viscosity by about an order of magnitude at 50 °C. The results clearly indicate that the quality of the effluent bitumen is significantly improved by the in situ deasphalting. Lowering the viscosity and the asphaltene content of the produced bitumen in situ may reduce the cost of diluent usage for transportation purposes and the following bitumen upgrading process. Deasphalting during solvent injection may occur through phase partitioning (precipitation) and subsequent deposition. It has been reported that asphaltene precipitation can be sensitive to temperature, pressure, solvent type, and solvent-oil

Figure 16. Viscosity and heptane-asphaltene concentration (wt %) of the effluent oil samples at five different n-butane injection rates.

ratio for given crude oil.34,35 In our experiments, asphaltene precipitation is not expected to be very sensitive to pressure within the operating range.36 The deposition of the asphaltenic phase could occur in different places, including reservoir, wellbore flow lines or processing facilities. It may lead to potential issues such as permeability damage of reservoirs, plugging in production tubing, and deactivation of catalyst in bitumen hydroprocessing.37−39 Asphaltene phase partition is the necessary condition but not the sufficient condition for asphaltene deposition.40 The partitioned asphaltenic phase is not necessarily deposited on the exact spot it is generated, and it could be transferred downstream or even produced along with effluent oil. Furthermore, the deposited asphaltenes might be eroded or entrained from the rock surface or pore throats and continue to migrate if the local hydrodynamic forces are high enough.41,42 The observed multiple changes of the bitumen production rate at elevated n-butane injection rate (Cases 4 and 5) may thus be attributed to the trapping and the dislodgment of asphaltene agglomerates. The buildup of the immobile asphaltene phase on the fracture surface and in the J


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Energy & Fuels

Figure 17. Heptane-asphaltene concentration (wt %) of the residual oil in each section of cores at five different n-butane injection rates.

matrix would reduce the fresh solvent contact with bitumen and enrich bitumen content in the mixing zone, resulting in the unexpectedly low solvent efficiency in our n-butane core floods. The local hydrodynamic force increases with the injection rate, which could entrain the asphaltene deposits. This process helps restore the initial solvent extraction efficiency during the onset of asphaltene processes. It can be clearly seen from Figure 4 that the initial recovery rate for high injection rates (6 and 10 mL/min) was restored after the first remarkable reduction of bitumen production. These results are consistent with previous studies where the n-alkane/crude oil mixture or live reservoir fluid was injected into reservoir cores where a sharp permeability damage was observed followed by the permeability restoration at high injection rate.43,44 The reversal of permeability reduction may be explained by pore throat opening, which happened when local shear forces are high enough to remove the partially plugged pore throats.40,45 The n-butane-to-oil ratio determines the dynamics of asphaltene behavior during liquid extraction under isothermal condition. Previous research has shown that the amount of precipitated asphaltenes and the size of asphaltene particles increase with the alkane-to-oil ratio.36,46−48 As the alkane-to-oil ratio increases, asphaltene aggregation proceeds more rapidly and the amount of asphaltenes deposited on the surface increases.48−50 Figure 17 shows the concentration of C7-asphaltenes in residual oils for different n-butane injection rates. It can be clearly seen from this figure that the asphaltene concentration in all sections at residual oil saturation is much higher than that of the original bitumen (13.2 ± 0.5 wt %). The average C7asphaltene concentration is above 50 wt % for all core sections

and the injection rate below and around the critical rate (2 to 4 mL/min), indicating the significant enrichment of the residual oil samples with asphaltenes. In addition, there is no clear correlation between the sectional asphaltene concentration and the injection rate. This result may be attributed to the fact that the ratio of total volume of n-butane injected to total volume of bitumen produced (or cumulative n-butane-to-bitumen ratio) is almost the same for all n-butane injection rate below and at 4 mL/min (Figure 14). However, the further increase in the n-butane injection rate to 6 mL/min resulted in a surprising, dramatic drop in asphaltene retention in all sections. Recall that the bitumen production rate leveled off when the n-butane injection rate increased above 4 mL/min (Figure 12), which indicated an increase in the cumulative n-butane-to-bitumen ratio. Such an increase would give rise to asphaltene aggregation and deposition as reported from the previous studies.48−50 However, at elevated local shear rate, the size of the asphaltene flocculation was reported to be smaller.51,52 The small-sized aggregates have a lower tendency to be trapped in the pore throats and are more likely to travel downstream and be produced.53 This may explain the observed sharp decrease in asphaltene retention (or the increase in the effluent asphaltene content shown in Figure 16) at the injection rate of 6 mL/min. Unfortunately, this explanation does not hold for the higher injection rate of 10 mL/min because the asphaltene retention appears to be at minimum for 6 mL/min for the range of nbutane injection rate from 0.5 to 10 mL/min (Figure 17). It can only be speculated at this point that deasphalting was greatly enhanced at 10 mL/min, which gives rise to asphaltene deposition and pore throat plugging by virtue of increased K


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Energy & Fuels

This understanding has been built through our continuous study of the effect of rock permeability, solvent type, and temperature on the solvent process, which is important to the development of highly efficient solvent process for fractured viscous oil reservoirs.

asphaltene particle concentration even though the particle size is reduced. This speculation may be supported by the higher average pressure drop for this case (9.4 kPa) than that for the n-butane rate of 6 mL/min (3.7 kPa). Moreover, a comparison of the production profiles shown in Figure 12 for the n-butane injection rates of 6 and 10 mL/min indicates that bitumen production at the restored rate (i.e., the rate observed after the first abrupt change in bitumen production rate) lasts significantly longer for the higher injection rate (i.e., almost one injected PV for 10 mL/min compared to 0.25 PV for 6 mL/min), resulting in higher ultimate recovery (67% for 10 mL/min compared to 55% for 6 mL/min). This observation may be attributed to the fact that more severe asphaltene precipitation at higher solvent-to-bitumen ratio leads to a more rapid buildup of asphaltene deposits that can be remobilized at sufficiently high local pressure gradients or hydrodynamic forces. The temporary dislodgment of the asphaltene aggregates improves solvent-undiluted bitumen contact and bitumen extraction.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. ORCID

Quoc P. Nguyen: 0000-0001-9129-8700 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This research was supported by Shell.

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REFERENCES

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CONCLUSION In this study, we investigated the effect of liquid n-butane injection rate on bitumen recovery and asphaltene deposition in artificially fractured Idaho Gray sandstone cores. Five solvent injection rates from 0.5 to 10 mL/min were chosen and core flood experiments were conducted at constant pressure and temperature. The extraction of bitumen was governed by three mechanisms: molecular diffusion, convection (and associated mechanical dispersion), and in situ deasphalting. As the n-butane injection rate increased from 0.5 to 4 mL/min, the local flow velocity increased, which enhanced the mass transfer between the pure solvent and the undiluted bitumen, and thus the bitumen production rate. However, the ultimate recovery factor (about 73%) remained unchanged, which is consistent with the nearly constant injected PV of n-butane required to reach the bitumen recovery plateau, over this range of injection rate. A further increase in the n-butane injection rate above 4 mL/min had a negligible effect on oil production rate, but resulted in the abrupt temporary reduction in the bitumen production rate and reduced ultimate recovery factor. The observed sharp recovery plateaus for all n-butane injection rates may be associated with asphaltene precipitation and deposition. Deasphalting is clearly indicated by the measured reduction of the viscosity and the asphaltene concentration of produced bitumen, as well as the relative increase in the effluent mass fraction of low-carbon-number components compared to the original bitumen. Furthermore, the temporary abrupt reduction and subsequent restoration of bitumen production rate observed at high n-butane injection rate (above 4 mL/min) is related to the interplay between asphaltene deposition and remobilization. The intense asphaltene precipitation and aggregation at high solvent-tobitumen ratio (or high solvent injection rate) accelerates asphaltene deposition and leads to the buildup of local pressure gradients. At sufficiently high pressure gradient (or hydrodynamic force), asphaltene dislodgment becomes significant, which would significantly assist in restoring solventbitumen contact and bitumen production rate. The findings from this work have advanced our understanding of the mechanisms of bitumen recovery and deasphalting under the conditions of liquid solvent extraction in fractured sandstones with permeability that is typical of bitumen formations (i.e., matrix permeability above 1 Darcy). L


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Viscous Oil Recovery and In-situ Deasphalting in Fractured Reservoirs

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