Article pubs.acs.org/EF
Bitumen Recovery from Carbonates by a Modified SOS-FR (SteamOver-Solvent Injection in Fractured Reservoir) Method Using Wettability Alteration Chemicals Mohammedalmojtaba Mohammed and Tayfun Babadagli* Department of Civil and Environmental Engineering, School of Mining and Petroleum Engineering, 7-277 Donadeo Innovation Centre for Engineering, University of Alberta, 9211−116 Street, Edmonton, Alberta T6G 1H9, Canada ABSTRACT: This study investigates the applicability of the modified version of the previously proposed SOS-FR (steam-oversolvent injection in fractured reservoir) method to recover bitumen from the Grosmont formation in Canada. Three phases were applied on a total of 13 preserved core samples. In Phase 1, the cores taken from three different parts of the Grosmont formation were soaked in a liquid solvent (heptane or distillate) at ambient conditions. The objective of the first phase was to reduce the viscosity of the bitumen in preparation for the second phase which is wettability alteration. In Phase 2, we soaked the samples in water with chemicals. Wettability modifiers tested include high pH solution, cationic surfactants, and ionic liquids because the screening process indicated they are the most useful wettability alteration chemicals for oil-wet carbonates. One of the key benefits of the ionic liquids is that they are environmentally friendly as they are chemically stable with low level of toxicity and flammabiliy. They can also be customized for particular rock/fluid system. On the other hand, pH solutions are economically attractive, in comparison with other wettability modifiers. Finally, Phase 3 was applied by increasing temperature to the bubble point of the solvent to mimic hot-water injection with chemicals. Each phase was analyzed in terms of ultimate oil recovery (and wettability alteration), time to reach this amount, the most suitable wettability alteration chemicals, and soaking times needed. The results revealed that the solvent phase not only affects the bitumen properties, but also changes Grosmont rock characteristics significantly. Wettability alteration of the fractured Grosmont reservoir was observed to be critical for additional oil recovery as well as for solvent retrieval. Specific high pH solution efficiently altered wettability and helped to recover considerable amount of bitumen/solvent mixture fairly quick showing a potential as a low cost chemical to recover bitumen. A discussion about the optimization of the process in terms of the solvent soaking period, wettability alteration chemicals, and the effect of temperature was also included.
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INTRODUCTION Naturally fractured carbonate reservoirs usually yield uneconomical oil recovery under conventional recovery processes due to their challenging rock characteristics.1 In addition to their heterogeneity and complex porosity and permeability structure, most of these reservoirs exhibit oil-wetness, which reduces the efficiency of any water-based recovery process. The Upper Devonian Grosmont Formation in Northern Alberta displays another complex feature in addition to its extreme heterogeneity. Bitumen in this naturally fractured reservoir is highly viscous and immobile under reservoir conditions.2 In their review of the research and development in Alberta’s bitumen carbonate reservoirs, Alvarez et al.2 addressed these problems and described wettability as a “key parameter” that should be carefully considered. It is estimated that around 406 billion bbls of bitumen are contained in the Grosmont formation.3This huge reserve, which is considered the largest heavy oil reserve in carbonates,4 drives the ongoing research interest in Grosmont to find viable means of recovery for this type of reservoir. Grosmont bitumen deposits are usually found in deeper formations than clastic formations in the same (Athabasca) region and this makes mining methods inapplicable. As a consequence of this, only in situ processes should be considered. Currently, two types of recovery processes have been tested: thermal and solvent-based recovery processes. Although some © 2016 American Chemical Society
pilot tests have delivered attractive results, there is no commercial development of Grosmont formation at this time.
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GEOLOGY AND SAMPLES TESTED The Grosmont formation is composed of dolomitized platform carbonate with a thickness up to 170 m.5 The pore system is complex consisting of matrix, vugs, and fractures porosity. The Grosmont formation is composed of four units, namely from the bottom to the top: A, B, C, and D. Most development efforts are now focused in Units C and D, which are separated by marl layer.6,7 Bitumen properties are quite similar to those found in the neighboring clastic formations, being a bit heavier with an API degree ranging from 5 to 9 and viscosity of about 1 600 000 cP.8 Water saturation can vary according to the type of facies. For example, MacNeil9 stated that water saturation may range from 20 to 30% while another study by Jiang et al.3 suggested a lower initial water saturation ranging from 5 to 10% The main feature of Unit C is the rich bitumen saturation with three typical reservoir facies: vuggy dolostones, “dolofudge”, and nonvuggy dolostones. Clasts in Unit D have a wide range of bitumen saturation while matrix has a tendency to have high bitumen saturation. Detailed descriptions of Received: January 25, 2016 Revised: April 20, 2016 Published: April 20, 2016 3849
DOI: 10.1021/acs.energyfuels.6b00176 Energy Fuels 2016, 30, 3849−3859
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Energy & Fuels
angle measurements indicated, Grosmont cores are strongly oilwet; all cores from GA plug were immersed into water to confirm this observation. The weak spontaneous imbibition of water indicates oil-wetness and the need for the wettability alteration phase. The second phase in the sequence of experiments was the wettability alteration where chemical solutions at different concentrations were tested. Experiments were performed at temperatures ranging from 25 to 65 °C. Finally, temperature was increased to 90 °C for additional recovery of oil and solvent retrieval. Experimental setup for thermal phases was similar to that described in our previous work.11
geological features of the Grosmont formation can be found in MacNeil.9 Three preserved cores named GA, GB, and GC were obtained from different formations of the Grosmont unit located in Alberta. Plugs GA and GB were cut from the same field cores while plug GC was cut from another one. While reservoir facies in Grosmont GA and GC can be described as hard and vuggy, they are mostly soft in Grosmont GB. In this paper, we will refer to cores from GB as the high quality ones. These plugs were obtained from the original cores with diameters of 1.5 in., and different lengths varying from 5 to 8.8 cm. Initially, five plugs were cut from the GA cores and five plugs from the GB cores. An additional three plugs were taken out from the GC cores. Experiments were conducted under static conditions using imbibition cells that were designed to allow only a narrow gap between the core sample and the edges of cell (1 mm). The representation of core samples in imbibition cell provides a good analogy to matrix−fracture interaction in NFCR reservoirs. One challenge of using the imbibition cell to evaluate the wettability of Grosmont is the high viscosity of bitumen, which makes it immobile under reservoir conditions. The bitumen can have a density similar to or higher than water, which means that even if bitumen is produced from the core, it may not float on water; instead, it may sink down to the bottom of the cell. Then, the weight difference calculation can be used in this case to estimate the bitumen recovery. Three phases were applied in most of the experiments: (1) solvent phase, (2) wettability alteration phase, and (3) solvent retrieval phase. Solvent phase was applied using heptane or distillate. The properties of heptane and distillate are shown in Table 1. The composition of the distillate can be found in a
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SOLVENT PROCESSES Considering the extra high viscosity of bitumen contained in Grosmont carbonate, which is in the order of 106 cP, solventbased processes may provide an attractive alternative to thermal strategies. About 50−60% bitumen recovery was achieved by soaking a Grosmont core into solvents.3 This experimental study was supported by the pilot test results conducted in the Saleski area. Edmunds et al.7 discussed the results of a pilot test carried out using solvent cyclic injection in a single well and indicated that both high permeability and high bitumen saturation support the feasibility of solvent injection in the Grosmont area. Jiang et al.3 compared the efficiency of warm and cold solvent injection and concluded that warm solvent injection is more favorable as it increases the diffusivity of solvent into bitumen. However, they also pointed out that increasing the temperature will decrease the solubility of solvent. Pathak et al.12 performed an experimental study to test the efficiency of hot solvent injection in Grosmont carbonate. Higher dilution and hence bitumen recovery was achieved by butane in comparison with propane. Based on their results, optimum temperature was found to be mildly higher than the saturation temperature under reservoir conditions. Naderi et al.10 reported that Steam-Over-Solvent Injection in Fractured Reservoir (SOS-FR) method can be used efficiently to produce bitumen from Grosmont samples.Their experimental study was performed using preserved Grosmont cores obtained from unit C. Up to 90% bitumen recovery was reported with about 62−82% solvent retrieval. The SOS-FR is based on the alternate injection of steam and solvent. While most of the bitumen is produced during the solvent phase, a steam phase is applied mainly to retrieve the solvent. After testing different scenarios, Naderi et al.10 demonstrated that cyclic solvent injection followed by hot-water phase is the optimum strategy for maximizing bitumen recovery from the samples. In our previous work, we showed that hot-water phase can be combined or replaced with a wettability alteration phase in which a low concentration wettability modifiers can be used.11 Different chemicals were screened for their ability to change the wettability of carbonate reservoirs and the most efficient ones were reported and tested experimentally using heavy oil containing Indiana limestone outcrop core samples. This study also showed that heavy oil containing oil-wet systems can be accessed using a two-step method; solvent injection followed by wettability modifier injection. In this study, we extend this recovery strategy into Grosmont carbonates, which possesses more complex characteristics in terms of rock and fluid properties. To our knowledge, no previous experimental
Table 1. Wettability Alteration Chemical Solutions no.
chemical type
chemical name
concentration
1 2 3 4 5
cationic surfactant ionic liquid 1 ionic liquid 2 high PH solution high PH solution
C12TAB [BMMIM][BF4] [BMIM][BF4] NaOH NaBO2
1 wt % 1 wt % 1 wt % 2.5 wt % 2.5 wt %
published work by Naderi et al.10 The wettability alteration phase was applied immediately after the solvent phase to prevent any solvent loss. The list of chemical solutions used in for wettability alteration is displayed in Table 2. The Table 2. Properties of Distillate and Heptane materials/properties
density (g/cm3) at 25 °C
viscosity (cP) at 25 °C
heptane distillate
0.684 0.738
0.386 0.742
concentrations of the chemicals were kept at low values. At the end of the wettability alteration phase, temperature was increased to a value at or around the bubble point of the solvent used in the solvent phase to retrieve it by vaporization. Experiments were initiated by immersing the core samples into solvent. Refractive index (RI) measurements, weight differences, and volumetric calculations were integrated to estimate the bitumen recovery during this phase. Solvent type and soaking period were two variables during the solvent phase. In one experiment, no solvent phase was applied. As contact 3850
DOI: 10.1021/acs.energyfuels.6b00176 Energy Fuels 2016, 30, 3849−3859
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Energy & Fuels Table 3. List of All Experiments
a
core no.
Grosmont plug type
length (cm)
porosity
obip (g)
solvent type
G1
GA
8.5
0.072
6.94
distillate
G2
GA
8
0.061
5.55
heptane
G3
GA
8.8
0.040
4.05
heptane
G4
GA
8.5
0.034
3.3
heptane
G5
GA
8.8
0.049
4.93
heptane
G6
GB
8.8
0.163
16.34
heptane
G7
GB
8.8
0.156
15.61
heptane
G8 G9
GB GB
6.5 6.9
0.188 0.140
13.92 11.03
heptane heptane
G10
GB
6.9
0.180
14.17
G11
GC
7.7
0.055
4.82
no solvent heptane
G12 G13
GC GC
6.9 5
0.075 0.1
5.91 5.73
heptane heptane
chemical type BMMIM BF4 (1.0 wt %) BMMIM BF4 (1.0 wt %) BMMIM BF4 (1.0 wt %) BMMIM BF4 (1.0 wt %) C12TAB (1.0 wt %) NaOH (2.5 wt %) NaBO2 (2.5 wt %) none BMIM BF4 (1.0 wt %) NaBO2 (2.5 wt %) C12TAB (1.0 wt %) none BMMIM BF4 (1.0 wt %)
temp range during thermal phases (°C)
soaking period solvent phase (3 weeks)−water (1 week)−WAa phase (12 weeks)−thermal phase solvent phase (3 weeks)−water (1 week)−WAa phase (12 weeks)−thermal phases solvent phase (3 weeks)−water (1 week)−WAa phase (12 weeks)−thermal phases solvent phase (1 week)−water (1 week)−WAa phase (12 weeks)−thermal phases solvent phase (3 weeks)−water (1 week)−WAa phase (12 weeks)−thermal phases solvent phase (3 weeks)−WAa phase (1 day)− thermal phases solvent phase (3 weeks)−WAa phase (8 weeks)− thermal phases solvent phase (3 weeks)−thermal phases solvent phase (3 weeks)−WAa phase (8 weeks)− thermal phases water at 65 °C (5 weeks)−WAa phase (169 days) a
solvent phase (3 weeks)−WA phase (8 weeks)− thermal phases solvent phase (3 weeks)−thermal phases solvent phase (3 weeks)−WAa phase (8 weeks)− thermal phase
90 65−90 65−90 90 65−90 90 90 65−90 90 65 90 65−90 90
WA: wettability alteration. OBIP: original bitumen in place.
results testing wettability alteration in Grosmont carbonate were published. Bitumen was recovered during the initial solvent phase by a dilution effect, reduction of bitumen viscosity, and gravity drainage. At the end of the solvent phase, porous medium contains bitumen mixed with solvent. The wettability alteration phase is then applied and if the wettability of the system is changed toward water-wetness, the mixture of bitumen and solvent can be displaced spontaneously by water. As the mixture has less density than water, gravity drainage may also contribute to spontaneous imbibition process. The wettability alteration phase was carried out first at 25 °C. The temperature was then increased to 65 °C for some cases. At the end of the wettability alteration phase, temperature was increased to be close to the bubble point of the solvent to collect the remaining solvent from the matrix. Ionic liquids, cationic surfactants, and high pH solutions were selected to be used in the present study as our previous study showed that they are the most efficient wettability modifiers for carbonate formation.11 Ionic liquids are believed to decrease the adhesive forces between carbonate and the oil-wetting materials that render the carbonate more water-wet. Cationic surfactants alter the wettability by ion-pair interaction.14 Many studies show that high pH solution reduces the positive charge on carbonate and thus decreases the attraction forces between rock surfaces and crude oil components. As a result, it can change the wettability of carbonate from oil-wet to water-wet. A detailed discussion of the effect of these chemical solutions on the wettability of carbonate reservoirs can be found on our previous work.11,13
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Figure 1. Grosmont plug GA. initially exposed to solvent phase. Sample G1 was immersed into distillate while G2−G5 were soaked into heptane. The objective of testing different solvents is to investigate the effect of solvent type on the process. Figure 2 shows the bitumen recovery during the solvent phase for the GA plugs.
DESCRIPTION OF EXPERIMENTS
A summary of all experiments performed in this study is provided in Table 3. All cores samples were preserved original Grosmont samples and there was no cleaning performed before starting the experiments. Pore volumes were calculated based on the volume and weight measurements after the cleaning process at the end of the experiments. Five plugs cut from the GA cores are shown in Figure 1. All cores were
Figure 2. Recovery during solvent phase for cores samples cut from Grosmont plug GA. 3851
DOI: 10.1021/acs.energyfuels.6b00176 Energy Fuels 2016, 30, 3849−3859
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Figure 3. Grosmont core during wettability alteration phase using (A) NaBO2 (G7) and (B) ionic liquid BMMIM BF4 (G3) with solvent phase. To confirm the oil-wetness of Grosmont, G1−G5 were put into water for 1 week and bitumen recovery during this period was monitored. Immediately after the water phase, wettability alteration phases were applied by soaking cores into different chemical solutions. Imidazolium ionic liquid BMMIM BF4 at 1.0 wt % was used as wettability modifier for G1. Sample G2 was also immersed into the same ionic liquid. This experiment was repeated using sample G3 for testing the reproducibility of the results. The soaking period for all cores except G4 was 3 weeks. For the G4 case, the soaking period was limited to 7 days. This was done to explore the effect of soaking period on the process. Wettability alteration for sample G5 was conducted using a cationic surfactant C12TAB at 1.0 wt % concentration. Five experiments were performed using Grosmont GB core sample. Samples G6−G9 were exposed to solvent phase before the wettability alteration phase while there was no solvent phase for experiment G10. Instead, G10 experiment was planned to examine the nonsolvent strategy with and without chemical addition. The efficiency of high pH solutions in altering the wettability of Grosmont carbonates was tested using two solutions with a pH range of 11−12. G6 was immersed into NaOH at 2.5 wt % at 25 °C for 1 day before increasing the temperature to 90 °C. As it was observed in a previous study11 that NaBO2 improved the water-wetness of limestone better than NaOH, we decided to test it in Grosmont. In experiment G7, wettability alteration phase was conducted using NaBO2 at 2.5 wt. Figure 3 shows the bitumen−solvent mixture during wettability alteration phase for G7 and G3. No wettability modification agent was used for G8; instead, it was placed into hot-water at 65 °C. Another ionic liquid from imidazolium group, BMIM BF4 at 1.0 wt %, was investigated on sample G9. A droplet of bitumen on the top surface of the Grosmont sample G9 that was immersed into ionic liquid BMIM BF4 is shown in Figure 4. Sample G10 was placed first into the imbibition cell filled water at 65 °C for 5 weeks. The water was then exchanged with NaBO2 solution (2.5 wt %) at 65 °C. There was no solvent phase applied to this sample. Some of the experiments above were repeated using 3 plugs cut from preserved Grosmont GC cores. Core samples were immersed into heptane for 3 weeks before the wettability alteration phase. C12TAB at 1.0 wt % was tested on sample G11. Similar to G8, G12 was soaked into hot water at 65 °C. Finally, G13 was soaked into imidazolium ionic liquid (BMMIM BF4) at 1.0 wt %. All experiments were exposed to solvent retrieval phase at 90 or 70 °C depending on the solvent used (i.e., heptane or distillate). Core samples were dried at the end of the experiments to evaporate all the solvent in the cores. The weights of the cores were monitored
Figure 4. Droplet of bitumen on the top surface of sample G9 that is immersed into ionic liquid BMIM BF4.
until they became stable, which indicated that all the solvent had evaporated. Cores were then cleaned with heptane and toluene for several weeks until there was no change in weight. Finally, all cores were dried to ensure there was no solvent left after cleaning.
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RESULTS AND ANALYSIS
Several assumptions were made to facilitate the calculations of bitumen recovery and solvent retrieval. It was assumed that the cores contained no initial water saturation and hence the pore volume was fully saturated with bitumen. It is worth mentioning that this assumption can cause an overestimation of the “absolute” amount of bitumen recovery as original bitumen in place is expected to be lower when water saturation is included. However, as this is mainly comparative study, results would still be reasonable to perform the required analysis. Note that water saturation is highly dependent on the specific type of facies, ranging from 5%, according to Jiang et al.3 up to 20% as reported by MacNeil.9 We, however, did not have any clear indication of the considerably high amount of water saturation in the samples used in the experiments. Original bitumen in place was estimated using the following equation: 3852
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Two parameters were tested during the solvent phase: solvent type and soaking period. For the GA samples, distillate had higher diffusion efficiency than heptane. Bitumen recovery for G1, which was soaked into distillate for 3 weeks, was about 65%, being about 21−25% higher than G2 and G5, respectively, which were immersed into heptane for the same soaking period. Naderi et al.10 reported similar observations indicating the efficiency of distillate compared to single component alkanes (heptane in specific). The bitumen recovery dropped to 28% OBIP for G4 when the soaking period was reduced to 1 week, indicating the importance of diffusion time on the process. Sample G2 was exposed to the same experimental conditions as G3 to test the repeatability of the results. It was observed that G2 had about 44% OBIP while G3 had an ultimate recovery of 47% OBIP. Although the experimental parameters for GB and GC core samples were kept the same during the solvent phase, significant differences in bitumen recovery between these core samples were observed due to quality of the samples. As seen in Figure 5, the lowest bitumen recovery from GB was 62% OBIP from core G6. G9 had the highest bitumen recovery during this phase with about 68% OBIP. Note that Jiang et al.3 observed about 50−60% OBIP recovery when they soaked Grosmont core samples from Unit C into a lighter solvent. As mentioned, the main objective of applying solvent phase is to reduce the bitumen viscosity and hence mobilize it. Samples (especially GB cores) are severely fractured. It appears that the solvent dissolves the bitumen that glues the clasts and consequently the structure disintegrates when bitumen is removed. In fact, small pieces from the samples were observed broken at the end of the solvent phase. Essentially, this characteristic needs to be considered while designing the exploitation scheme. As will be discussed later, this “dissolving effect” led to an improvement of bitumen recovery during the subsequent phases for the samples cut from GB cores. As depicted in Figure 5, the bitumen recovery from GC core samples was between 39% and 44%. The recovery performance of GC was more similar to GA core samples (both are lower grade samples as indicated by the OBIP in Table 3 than GB core samples, although GA and GB belong to the same field and GC was cut from a different one). Wettability Alteration Phase. Oil-wet matrix in NFCR retains oil by capillarity and therefore no spontaneous imbibition of water was expected. In their discussion on the mechanisms of recovery in a Saleski pilot, Yang et al.5 stated that wettability of bitumen reservoir might change from oil-wet to water-wet at 150 °C and thus bitumen would be displaced by spontaneous imbibition referring to an analytical modeling study by Al-Hadhrami and Blunt.15 To test the wettability of the Grosmont core samples used in this study, all the core samples cut from GA were first exposed to cold water phase at 25 °C for 1 week after solvent exposure. One can see in Figure 6 that the recovery of bitumen−solvent mixture during this period was low (blue part of the bars). In fact, the viscosity of the mixture that was produced by the sample was found to be less than 0.5 cP, which indicates that this mixture was mostly solvent and no bitumen was recovered. It was expected that the solvent diffused into matrix was separated and some portion of it was produced by gravity difference. Hence, having no bitumen (or heavier components) in the produced oil, one may conclude that no capillary imbibition took place and the tested Grosmont samples were still oil-wet. Then, wettability alteration was essentially needed to access the bitumen−
original bitumen in place, g = initial weight of the core, g − final weight at the end of the cleaning process, g
(1)
The final recovery is calculated as follows: final bitumen recovery = [initial weight of the core, g − final weight of the core at the end of experiments, g]/[original bitumen in place, g]
(2)
Bitumen recovery during the solvent stage was estimated by the refractive indices and confirmed by weight difference calculations. The refractive index method directly gives the oil percentage in the solvent-bitumen mixture. In weight difference calculations, the bitumen recovery is calculated as follows: bitumen recovery (solvent phase) = final bitumen recovery − bitumen recovery in nonsolvent stages
(3)
Nonsolvent stages may include more than one stage including water/hot water/wettability alteration. Bitumen recovery in non solvent stages was measured directly by taking the volume of bitumen produced after evaporating all the solvent. The results from the refractive index measurements and weight difference calculations were then correlated to estimate the bitumen recovery during solvent phase. When the bitumen recovery during the solvent phase is estimated, it is possible to obtain the amount of solvent retrieved by deducting it from the total amount of diluted bitumen recovery that is measured during the imbibition process. Solvent Phase. The exploitation of bitumen reservoirs in clastic and carbonate formations poses great challenge due to their high viscosity and immobile status. Solvent can significantly reduce the viscosity of bitumen being more effective than heating as discussed earlier.10 Reduction of bitumen viscosity accelerated gravity drainage resulting in substantial bitumen recovery during the solvent phase. The average recoveries during solvent phase for lower quality samples (GA and GC) were 42% from OBIP. Samples cut from the high quality core (GB) had notably better performances compared to the others (average of 65% OBIP) (Figure 5).
Figure 5. Bitumen recovery during solvent phase for all core samples (OBIP: original bitumen in place). 3853
DOI: 10.1021/acs.energyfuels.6b00176 Energy Fuels 2016, 30, 3849−3859
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Figure 6. Diluted bitumen recovery during water and wettability alteration phase from GA core samples (PV: pore volume).
Figure 7. Diluted bitumen recovery during wettability alteration phase for GA core samples (IL1: ionic liquid 1).
solvent mixture or the “diluted bitumen” that left in the core samples at the end of the solvent phase. In the analyses given in this section, the term “diluted bitumen recovery” refers to the produced mixture during spontaneous imbibition of chemical solutions. This amount will be broken down into two elements: bitumen recovery and solvent retrieval. First, the wettability alteration phase was performed at room conditions (25 °C). When the diluted bitumen recovery leveled off, the temperature was then increased to 65 °C. The diluted bitumen recovery from GA core samples is displayed in Figure 6. The imbibition curves for different GA core samples are shown in Figure 7. Wettability modifier used for most of experiment was ionic liquid except for G5 where C12TAB was applied. One can observe that G4 had faster imbibition than the other cores. Note that soaking period for all GA core samples was 3 weeks except for G4. As reported earlier, G4 had the lowest bitumen recovery during the solvent phase and thus it is possible that the short soaking period did not allow solvent to penetrate deep into the core. Therefore, it was easy to drain this solvent-bitumen mixture from the outer parts (near to the surface) of the core. Among the other cores that were immersed into heptane for the same soaking period, G5 had the fastest imbibition. This
sample was immersed into a cationic surfactant (C12TAB), which is known as one of the best wettability modifiers for carbonates.13,14 Although G1, which immersed into an ionic liquid solution (BMMIM BF4), had slightly slower imbibition than G5 in the beginning, the imbibition rate of G1 sped up and exceeded G5 after the fourth week. Its recovery reached 38% of pore volume PV, the highest among all cores under the ambient conditions. All these observations reveal that the presolvent phase affects the behavior of imbibition; i.e., wettability alteration. G1, which was exposed to distillate, had a better recovery during the solvent phase than the other cores. Although the ionic liquid was used as a wettability modifier with G2 and G3 as in G1, they both had lower diluted bitumen recovery. Only 18% PV mixture of bitumen and solvent was recovered by G2 and decreased to 14% PV for G3. As both G2 and G3 had similar experimental conditions, they can be considered as repeatability tests for the wettability alteration phase. Increasing the temperature of the system to 65 °C was observed to enhance the imbibition. Higher temperature experiments were performed to test the option of hot water injection with chemicals. The diluted recovery jumped about 30% PV for G2, G3, and G5, which was more than thermal 3854
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Figure 8. Diluted bitumen recovery during wettability alteration phase for GB core samples. The recovery rate for G6 is given in the inset at a different time scale.
Figure 9. Diluted bitumen recovery during wettability alteration phase for GC core samples (IL1: ionic liquid 1).
expansion of oil that can be obtained with 40 °C increase in temperature (even the lowest additional recovery obtained from G4 [10% PV] was beyond the recovery that thermal expansion can generate). Different types of low concentration chemical solutions were tested for the GB samples. Directly after the solvent phase, G6 was immersed into NaOH solution. The imbibition of NaOH solution was remarkably fast. The droplets of bitumen-solvent mixture started coming out of the core from the first minute. More than 55% PV diluted bitumen was recovered in order of hours (Figure 8). Other chemical solutions that were tested on GB include NaBO2, hot-water at 65 °C, and ionic liquid. High pH solution (NaBO2) had faster imbibition than other chemicals and was able to recover about 39% PV diluted bitumen recovery (Figure 8). When hot-water at 65 °C was applied on G8, the diluted bitumen recovery was fast initially but reached its peak at 18% PV, which was the lowest value among all wettability modifiers.
The spontaneous imbibition of ionic liquid BMIM BF4 was slow at the beginning and then started increasing and exceeded the hot-water imbibition. The diluted bitumen recovery was finally stabilized at 22% PV. As previously mentioned, high pH solutions are found to have an exceptional performance compared with other wettability modification materials. It was shown in the previous section that GB core samples had rather high bitumen recovery during the solvent phase and the cores became severely fractured. It is possible that this good performance of high pH solution may be supported by the fractures that were created during the solvent phase. Thus, it was decided to skip the solvent phase to investigate the effect of high pH solutions on Grosmont carbonates targeting a cheaper process. To test this option, first, core G10 was put into hot-water at 65 °C for 5 weeks to examine if it could imbibe into the Grosmont rock. No bitumen was produced. The water was then exchanged with 2.5 wt % NaBO2 solution and a positive response was observed. 3855
DOI: 10.1021/acs.energyfuels.6b00176 Energy Fuels 2016, 30, 3849−3859
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Figure 10. Bitumen recovery and solvent retrieval during wettability alteration phase.
slightly lower temperature (70 °C) was applied for the distillate case (sample G1) considering it contains lighter components (aromatics and alkanes such as pentane and hexane). To recover the higher carbon number parts of this particular solvent, average carbon number of the distillate was given as 11−13 by Naderi et al.10 Bitumen Recovery and Solvent Retrieval During Wettability Alteration Phase. Bitumen recovery and solvent retrieval during the wettability alteration phase (water/ wettability alteration at 25 °C/wettability alteration at 65 °C) are displayed in Figure 10. The solvent retrieval for most of the GA cases was slightly below 90% for G2, G3, and G5. There was no significant difference in solvent retrieval between the cases where C12TAB was used for wettability alteration (G5) or BMMIM BF4 (G2 and G3). When the soaking period was reduced for G4, the solvent retrieval decreased to 72%. The solvent retrieval dropped to about 60% when distillated was used as a solvent (sample G1); the lowest value among other GA samples. Carbon number of distillate is higher than heptane, but it contains aromatics with lower boiling point. Higher temperatures may be needed for better solvent retrieval. The bitumen recovery was not significantly affected by the length of the preceding solvent phase. Recoveries from samples G2 and G3 were quite similar (about 15% OBIP). G4, which had a shorter soaking period, recovered the lowest bitumen during the subsequent phase. In this phase, bitumen recovery was 32% OBIP, which exceeded that of longer soaking period cases. This may be attributed to the higher residual bitumen saturation left in the core after the solvent phase. C12TAB produced more bitumen than ionic liquid (sample G5 with 31% OBIP recovery). High pH solutions were more efficient than other wettability modifiers in GB core samples as they recovered more bitumen and retrieved higher amount of the solvent. NaOH, which was tested on G6, recovered about 20% OBIP (5% higher than when was NaBO2 applied on G7). NaOH was able to retrieve about 56% solvent, which was about 18% higher than was retrieved by NaBO2. The other two scenarios tested were hotwater at 65 °C as a wettability modifier for G8 and ionic liquid BMIM BF4 for G9. In both cases, only about 8% bitumen was
Bitumen started detaching from the sample surface and some droplets of bitumen floated on water, while others sank to the bottom of the imbibition cell. It was difficult to measure bitumen that sank down and therefore the final weight of the core was used to correct the imbibition curve shown in Figure 8. The bitumen recovery reached 39% PV after about 169 days of imbibition. Such a recovery is significantly high considering that no solvent phase was applied. This promising performance of high pH solutions in such challenging oil-wet systems suggests the existence of other mechanisms that assist with diluted bitumen recovery in addition spontaneous imbibition. One possible mechanism is the reaction of high pH solutions with acidic components in the bitumen that generate in situ surfactants.16 The produced surfactants can enhance the release of bitumen from the carbonate. Srinivasan et al.17 concluded that high pH assists the progress of bitumen liberation from oilsands. As seen in the GA cases, the imbibition of hot-water at 65 °C was also fast in G8. However, the diluted bitumen recovery was just below 18% PV, which was the lowest among GB core samples. Even though G9, which immersed in ionic liquid BMIM BF4, started producing diluted bitumen in slower rate than G8, it eventually exceeded it reaching an ultimate bitumen recovery of 21% PV. Figure 9 shows the diluted bitumen recovery for GC core samples. As expected, hot-water at 65 °C, which was applied on G12, had a better performance than other wettability modifiers in early time. As time progressed, the rate of C12TAB imbibition into G11 increased and the diluted bitumen recovery from G11 exceeded G12 and peaked at 54% PV. The lowest diluted bitumen recovery was obtained by G13, which was immersed into ionic liquid BMMIM BF4 and was only 11% PV. Overall, C12TAB was efficient for all types of Grosmont and high pH solutions were good wettability alteration agents for GB and GC samples. Hot-water was more efficient than ionic liquid. At the end of the wettability alteration phase (water injection with chemicals), all core sample that were soaked into heptane were exposed to 90 °C hot-water to investigate the efficiency of solvent retrieval by hot water. Here, 90 °C is the boiling temperature of heptane at the atmospheric pressure, and 3856
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Figure 11. Bitumen recovery and solvent retrieval during solvent retrieval phase.
Figure 12. Final bitumen recovery for all core samples.
Figure 13. Final solvent retrieval for all core samples.
65 °C in terms of solvent retrieval even though both scenarios had almost the same diluted bitumen recovery. In the experiments with GC samples, the bitumen recovery exceeded the solvent retrieval in two cases (G11, G13). The
recovered. The measurements show that solvent retrieval for G9 was about 28%, which is twice as much as that obtained by G8. This indicates that ionic liquid is better than hot-water at 3857
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chemicals. The imbibition almost reached a plateau on the order of hours for NaOH. To be efficiently able to alter the wettability of Grosmont samples, chemical solutions must be injected at a moderately high temperature (60 °C). Cationic surfactant C12TAB shows promising results as a wettability modifier as well as high pH solutions, which are able to recover bitumen from Grosmont with or without the solvent phase. Ionic liquid BMIM BF4 has the tendency to reduce the water contact angle on Grosmont GB carbonate and thus alter the wettability to be more water wet. On the other hand, BMMIM BF4 is able to alter the wettability of Grosmont GA; however it did not show encouraging results with Grosmont GC. Solvent can be retrieved from Grosmont using chemical solution as wettability modifier. A solvent phase that is followed by wettability alteration phase using high pH solution or cationic surfactant is suggested as a feasible recovery scheme for the Grosmont bitumen carbonates. High pH solution is attractive because it is cheaper than many other wettability alteration agents.
wettability modifier used for G11 was C12TAB. This indicates that the type of wettability modifier may affect the “quality” of the produced bitumen during the wettability alteration phase. A similar observation was made for G13, which was immersed into BMMIM BF4 ionic liquid. The bitumen recovery from G11 was about 39% OBIP, which is about 20% higher than G12, which was exposed to hot-water at 65 °C. The lowest recovery was obtained by G13. Solvent Retrieval Phase. The solvent retrieval is crucial for the economics of the solvent-based processes. The remaining of the solvent in the core samples at the end of wettability alteration phase was captured by increasing the temperature of medium to be close to the bubble point of the solvent used. For heptane, the temperature was 90 °C and for distillate the temperature was kept at 70 °C. The retrieved solvent collected during this phase in addition to bitumen recovery is shown in Figure 11. While it was possible to retrieve considerable amount of solvent from GA core samples in addition to bitumen recovery, recoveries were very low for the samples cut from GB, except for G6. Note that these cores have remarkably high recoveries during the subsequent phases. Although there was almost no bitumen recovery from the GC samples during this phase, considerable amount of solvent was retrieved. In particular, G13 had about 81% solvent retrieval. The final bitumen recoveries obtained through all phases applied are shown in Figure 12. Clearly, most of the bitumen recovery occurred during the solvent phase. The highest recoveries were obtained from G7 and G11 (about 85% OBIP) while G13 yielded the lowest recovery among all that were exposed to solvent phase followed by the wettability alteration phase. When there was no solvent used and NaBO2 was applied as a wettability modifier directly (G10), bitumen recovery was slightly below 40%, which is highly encouraging economically. Figure 13 presents the final solvent retrieval from all core samples. GA core samples showed the highest solvent retrieval followed by the GC samples. The lowest amount of solvent was retrieved by GB core samples, which also had the highest bitumen recovery. Note that the lowest solvent retrieval occurred in G8 when there was no wettability alteration agent used and only moderate hot water was applied.
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS This research was conducted under the second author’s (T.B.) NSERC Industrial Research Chair in Unconventional Oil Recovery (industrial partners are CNRL, SUNCOR, Touchstone Exp., Sherritt Oil, APEX Eng., Husky Energy, Saudi Aramco and PEMEX) and an NSERC Discovery Grant (No. G121210595). We gratefully acknowledge this support. This paper is the substantially revised and improved version of OTC-26073 presented at the Offshore Technology Conference Brazil held in Rio de Janeiro, Brazil, 27−29 October 2015.
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CONCLUSIONS The Grosmont cores examined during this study are oil-wet and highly heterogeneous in terms of bitumen saturation. It was discovered that it is possible to recover up to 85% OBIP using the modified SOS-FR method suggested in this study. In addition, solvent phase is essential to dilute the bitumen and improve recovery. Solvent will then be retrieved efficiently using low concentration chemical solutions with additional bitumen recovery. This can be an alternative to solvent retrieval by heating the sample as suggested by Babadagli and AlBahlani18 and Al-Bahlani and Babadagli.19,20 Solvent also causes substantial change in the Grosmont GB rock structure by dissolving the bitumen that binds the grains together, and by the end of solvent phase, core samples become severely fractured and fragile. Different soaking periods and solvents were tested during this study. The best performance is obtained when distillate was used as a solvent for a 3-week soaking period. The most efficient wettability alteration agents, among other chemical solutions tested, were found to be high pH solutions (11−12 pH) and cationic surfactant C12TAB. Both NaOH and NaBO2 result in faster and higher recovery compared with other
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ABBREVIATIONS SOS-FR = steam-over-solvent injection in fractured reservoir OBIP = original bitumen in place PV = pore volume C12TAB = C12N(CH3)3Br IL1, BMMIM][BF4] = 1-butyl-2,3-dimethylimidazolium tetrafluoroborate IL2, [BMIM][BF4] = 1-butyl-3-methylimidazolium tetrafluoroborate REFERENCES
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