CA2069515A1 - Separation of bitumen and water in a separator vessel - Google Patents

Abstract

"SEPARATION OF BITUMEN AND WATER IN A SEPARATOR VESSEL"

ABSTRACT OF THE DISCLOSURE
The feedstock to the process is the produced fluid emulsion from a steam-assisted gravity drainage process conducted in a subterranean oil sand reservoir. This stream is an emulsion of bitumen and water. The feedstock is temporarily retained in a gravity separation vessel for about an hour at elevated pressure and at a temperature of at least 205°C, preferably about 215°C, in contact with an effective concentration of chemical demulsifier. Under these temperature conditions, the density of the bitumen is sufficiently greater than that of the water so that gravity separation will occur effectively and the bitumen can be recovered from the base of the vessel and the water from the upper portion of the vessel.

Description

206.~515 2 This invention relates to a process for treating a 3 bitumen/water emulsion to separate the emulsion components.

The assignee of the present invention has recently 6 developed a novel process for recovering bitumen from 7 subterranean Athabasca oil sand. This process has involved:

8 - sinking vertical shafts through the overburden and 9 buried cil sand to penetrate into the competent limestone underlying the oil sand;
11 - excavating horizontal drifts or tunnels from the 12 shafts in the limestone;
13 - drilling pairs of parallel wells upwardly from a 14 tunnel into the oil sand and then extending them horizontally through the oil sand along its base, 16 the wells being closely spaced vertically (5-8m) 17 and being co-extensive;
18 - establishing fluid communication between the wells 19 by conduction heating of the span of formation extending vertically between them, by circulating 21 steam simultaneously in the two wells to create 22 two closely spaced, parallel "hot fingers"; and 23 - then converting the upper well to steam injection 24 and the lower well to produced fluid production, the steam being supplied from ground surface 26 through a line extending down through the shaft 27 to the upper well and the production being 1 produced from the lower well through a line 2 extending up the shaft to ground surface.
3 This steam injection/emulsion production process using 4 a pair of wells is referred to as a steam-assisted gravity drainage (SAGD) process.
6 The product from the SAGD process is a hot emulsion, 7 under pressure, of bitumen and condensed steam or water, 8 containing some solids.
9 Hot emulsions of bitumen, water and solids are produced in the conventional surface-mined oil sand operations of Syncrude 11 and Suncor. These emulsions typically have a temperature of 12 80C. The separation of bitumen and water in these plants is 13 carried out by diluting the emulsion with a bitumen solvent 14 (naphtha) and then centrifuging the mixture. The naphtha dilution serves to increase the differential in density of the 16 water and bitumen, thereby enabling successful separation of the 17 emulsion components by centrifugation. However this is an 18 expensive approach as some of the naphtha is lost and the balance 19 has to be recovered - in addition, the centrifuges are expensive to operate.
21 It would therefore be desirable to provide a simpler 22 process for separating the bitumen and water in the emulsion.
23 The bitumen product will likely be sold to nearby refineries, 24 such as those of Syncrude and Suncor; they specify that the water content of the bitumen product should be less than about 5 wt.
26 ~-27 It is the objective of the present invention to provide 28 such a process.

2069515 ~

SUMMARY OF THE INVENTION
2 In accordance with the invention, the hot emulsion 3 produced by the SAGD process is introduced into a gravity 4 separator vessel at a temperature greater than 205C, preferably at about 215C, and at elevated pressure (typically about 3000 6 kPa). A chemical demulsifier of conventional type is also 7 introduced into the separator. A conventional reverse emulsion 8 breaker (REB) may also be introduced. The mixture is retained 9 in the separator vessel for sufficient time (typically an hour) so as to enable substantially complete separation of the emulsion 11 components to occur. The bitumen product is drained through an 12 outlet in the base of the separator vessel and normally contains 13 less than about 5 wt. % water. The water is removed from the 14 separator vessel through an outlet higher than that of the bitumen outlet. This water product contains little bitumen 16 (typically 2 wt. % or less).
17 The invention is based on the discovery that, with 18 increasing temperature, the densities of produced bitumen and 19 water remain about the same until about 125C at this point, an increasing density differential becomes manifest. The density 21 of the bitumen at these +125C temperatures is greater than that 22 of the water. At a temperature greater than 205DC, preferably 23 about 215C, the density differential is sufficient to enable the 24 required degree of gravity separation to occur in a separator vessel in a practical retention time. This end can be reached 26 without having to resort to the addition of solvent diluents, 27 although chemical demulsifier is required.

206~

1 Broadly stated, the invention is a method for 2 separating water and bitumen present in the emulsion fluid 3 produced from a steam assisted gravity drainage process being 4 applied to a subterranean oil sand reservoir, comprising:
retaining the fluid, in contact with an effective concentration 6 of demulsifier, in a separator vessel operated at elevated 7 pressure and a temperature of at least 205C for sufficient time 8 to effect gravity separation of the bitumen and water; and 9 recovering a bitumen production stream containing less than about 5% by weight water and a water production stream containing less 11 than about 2% by weight bitumen.

13 Figure 1 is a schematic perspective view of the present 14 assignee's underground test facility used to practice bitumen/water emulsion recovery using the SAGD process;
16 Figure 2 is a plot comparing the density of SAGD water 17 and bitumen with increasing temperature;
18 Figure 3 is a schematic showing the high temperature 19 and pressure separator circuit used to test the invention;
Figure 4 is a side sectional view showing the separator 21 vessel of Figure 3;
22 Figure 5 is an end sectional view of the separator 23 vessel of Figure 4;
24 Figure 6 is an end view, at the line A, of the vertical baffle at the inlet end of the separator vessel;
26 Figure 7 is an end view, at the line B, of a vertical 27 weir at the outlet end of the separator vessel;

206~515 1 Figure 8 is a plot showing flow rates into and out of 2 the separator vessel during the test;
3 Figure 9 is a plot showing separator vessel 4 temperatures during the test;
Figure 10 is a plot showing water cuts at the separator 6 vessel feed inlet, bitumen outlet and water outlet during the 7 test;

8 Figure 11 is a plot showing demulsifier and 9 clarifier/REB concentration in the separator vessel during the test; and 11 Figure 12 is a plot showing bitumen cuts in the 12 production from the water outlet during the test 14 The invention is supported by two distinct experimental efforts.
16 In the first effort, the temperature dependence of 17 bitumen density was assessed. Figure 2 plots the changing 18 density of each of produced SAGD water and bitumen with 19 increasing temperature. As previously stated, the bitumen density is about the same as that of water in the temperature 21 region 50 - 125C. However, at about 125C the density 22 differential between bitumen and water begins to increase 23 steadily, as shown.
24 The separation of SAGD water and bitumen was then tested in the bench scale, flow through, high temperature and 26 pressure separator circuit shown in Figure 3. The separator 27 circuit was located in a tunnel in the underground test facility 28 of Figure 1.

206~

1 During testing, the wells 1 of the SAGD project were 2 in a "blowdown" stage. Therefore a positive dlsplacement booster 3 pump 2 was used to increase the emulsion pressure to about 3000 4 kPa. The pressurized emulsion was then routed through a gas separator 3, to remove non-condensable gases, and heated to about 6 220C in a shell and tube heat exchanger 4. Chemical demulsifier 7 was introduced to the flow at one of the injection points shown 8 in Figure 3. The heated, pressurized emulsion was fed to a 610 9 mm diameter x 3048 mm long gravity separator vessel 5. The incoming feed entered and accumulated in a feed chamber 6. It 11 overflowed through the port 7 of a baffle 8 into a main 12 coalescing and separation chamber 9. An interface weir 10 was 13 positioned at the far end of the vessel 5, directly ahead of a 14 bitumen outlet 11 and water outlet 12. A radio frequency type interface probe 13 was positioned downstream of the interface 16 weir 10. When the probe 13 detected the bitumen-water interface, 17 a valve 14 on the water outlet line 15 would close and bitumen 18 would be flushed through the bitumen outlet 11. The emulsion 19 flow rate to the separator 5 and the bitumen flow rate from the outlet 11 were measured by mass flow meters 16, 17.
21 Three inlet flow rates were tested, as shown in Figure 22 8. These were approximately 7.2 m3/d (total fluid), 9.6 m3/d and 23 17.5 m3/d. With a vessel capacity of 0.64 m3, the corresponding 24 residence times were 2.1 h, 1.6 h, and 9.9 h.
The nominal separator vessel design temperature and 26 pressure were 260C and 7000 kPa. The separator was maintained 27 at 2300 kPa until day 16. The pressure was then increased to 28 2850 kPa for the remainder of the test. The separator was 29 operated at approximately 195~C until day 18. The temperature 206~51~

1 was then increased in an effort to improve performance. When the 2 separator temperature reached about 205~C - 215C, significant 3 improvements in ~itumen and water cuts were observed. This 4 temperature range was maintained as the target for the remainder of the test.
6 Figure 9 shows temperatures measured at various 7 locations in the separator vessel. Early in the test a 8 significant vertical temperature gradient was observed. On day 9 10 there was a 30C difference between the top and side temperatures. Ten centimetres of fibreglass insulation were 11 added to the existing ten centimetres on day 12 and the 12 temperature difference was reduced to approximately 18C.
13 Increased insulation of exposed piping and fittings and increased 14 flow rates eventually reduced the difference to 10C by the conclusion of the test.
16 ~he separator was operated with no internal coalescing 17 baffles until a shut down on day 32. At this time, a pair of 18 baffles were installed for evaluation. A test of an alternate 19 baffle design was carried out from day 71 until the test was completed. It was concluded that the impact of the baffles was 21 minimal.
22 During the test, over 1000 samples were taken for the 23 detsrmination of bitumen and water cuts. A daily average of the 24 cuts is shown in ~igure 10. Bitumen and water cuts were determined by drawing off a cooled sample and analyzed on ~ite 26 by standard oil field centrifuge methods. The samples were also 27 sent to a laboratory for Dean Stark analysis to confirm these 28 centrifuge results. Samples were obtained primarily from three 2~6951~

1 locations. The emulsion inlet, the bitumen outlet and the water 2 outlet.
3 The inlet emulsion varied between 55% and 75% by wt.
4 water. The fluctuation was due to normal changes in production.
The average was 68% water.
6 The water cut of the production from the bitumen outlet 7 11 varied between 5 - 15 wt. % during days 1-18, when the vessel 8 contents temperature was about 195C. Starting on day 18 the 9 temperature of the vessel contents was raised and reached about 215C on about day 20. After the temperature was so increased, 11 water cuts of less than 5% were normal at the bitumen outlet.
12 Obtaining "clean" water at the water outlet 12 was more 13 difficult. The average bitumen cut in the production from the 14 water outlet was high, up to about day 24. In this connection, the separator vessel was initially operated for three days 16 without any chemical additives. During those days, the water cut 17 at the bitumen outlet was about 30%. The injection of Champion 18 x 8881 oil phase chemical demulsifier was initiated on day 4 at 19 injection point 1. Between days 4 and 18, concentrations ranging 20 from 200 ppm to 1200 ppm (based on total fluid) were tried.
21 Results were generally poor, as shown in Figure 10. Beginning 22 on day 18, the vessel temperature was increased and moving the 23 chemical injection point was tried. More specifically, on day 24 18 the inlet temperature was raised to about 220C. This change was reflected in less than 5% water in the production from the 26 bitumen outlet; however the production from the water outlet 27 still had a bitumen content of about 20%. An examination of the 28 water outlet production showed that most of the bitumen droplets 29 1 Trade-Mark ; 9 206951~

1 were less than 2 microns in diameter. It was felt that these 2 fine droplets interfered with mixing of the demulsifier with the 3 bitumen. The fine emulsion may have been caused by shearing of 4 the fluid in a booster pump upstream of the separator vessel.
The original demulsifier injection point 1 was downstream of the 6 pump 2. On day 25, the demu]sifier injection point was moved 7 upstream of the pump to injection point 2. At the same time, the 8 demulsifier concentration was increased to 1700 ppm. Following 9 these changes, the bitumen cut in the water outlet production decreased to about 5%. On day 26, injection of Champion ZB 153 11 water clarifier was commenced while continuing the demulsifier 12 injection. On days 30 and 31 the bitumen cuts in the water 13 outlet production decrsased to about 1% and the amount of water 14 in the bitumen outlet production was about 2.5%.
As shown in Figure 9, the vessel temperature fell from 16 215C on day 26 to 195C by day 30. The decline in temperature 17 began almost immediately following clarifier injection. It was 18 felt that the water soluble clarifier chemical was being 19 deposited on the heat exchanger tube surfaces. The process was shut down during days 32-36 to steam clean the heat exchanger 21 tubes.
22 The operations to this point could be described as a 23 learning phase. The complexities and interplay between chemical 24 rates, injection point locations and vessel temperature had become apparent. The demulsifier concentration still had to be 26 optimized in hopes of reducing it to a level lower than 1700 ppm.
27 The effects of moving the clarifier injection point and 28 experimenting with other clarifiers and reverse emulsion breakers 29 (REB) also remained to be examined.

2~69~1~

1 After restart on day 36, the separator inlet 2 temperature was maintained between 210C and 220~C until the end 3 of the test. With high temperatures now maintained, demulsifier 4 optimization was attempted. Between days 36 and 46 the Champion X888 concentration was varied between 200 ppm to 1500 ppm. On 6 day 46 the rate was adjusted to 450 ppm and this concentration 7 was maintained until day 81. This resulted in water in bitumen 8 production stream cuts of between 2.5% and 5%.
9 Although the bitumen outlet production water content had improved significantly, there was still as much as 10%
11 bitumen in the water outlet production stream. Inje~tion of a 12 new clarifier chemical (Champion ZXW108) was started on day 40.
13 The clarifier was added down stream of the heat exchanger 14 directly to the separator vessel at Injection Point 3. This clarifier was tested until day 53, with poor results. Cuts in 16 the water outlet production were between 5% and 10%. The 17 chemical was replaced with Baker Oil Treating's R5302 reverse 18 emulsion breaker (REB) on day 53. Nater quality improved to 1%
19 to 2% bitumen, but results were not as good as those obtained earlier with Champion ZB153 water clarifier. In a final attempt 21 to improve the water quality the REB injection point was moved 22 to the vessel inlet at Injection Point 4. Results improved 23 dramatically, due to better mixing of the REB. Figure 12 shows 24 a plot of bitumen concentration in the production at the water outlet hetween day 58 and the end of the test (day 83). Cuts as 26 low as 275 ppm were obtained.

2~6~15 1 The defined treatment objectives of less than 5% water 2 in the bitumen production stream and 2000 ppm bitumen and solids 3 in the water production stream were met and exceeded at 4 temperatures as low as 205C, residence times of less than one hour, and chemical injection rates of 200 ppm demulsifier and 200 6 ppm REB.
7 The main source of emulsion in the bench scale test was 8 created by shearing either in the booster pump or bypass control 9 valve. Addition of demulsifiers and reverse emulsion breakers upstream of the point where the emulsion was formed was effective 11 in offsetting the formation of stable emulsions.
12 It was important to identify factors contributing to 13 emulsion stability, such as the droplet size distribution and the 14 presence of clay fines, and other interfacial constituents. The presence of a clearly defined water/bitumen interface throughout 16 the test indicated that the process successfully overcame these 17 stabilizing factors. The combination of high temperature and 18 chemical treatment was effective in destabilizing all emulsions 19 encountered.
Predetermination of oil phase viscosity and density 21 relative to the water phase over the operating temperature range 22 was critical in understanding the conditions which affected 23 normal separation. The bench scale test and laboratory work 24 clearly defined the effect of temperature on separation. With increasing temperature both the viscosity and density difference 26 were working to promote separation.

2~6~

1 Coalescence of water droplets in the vessel did not 2 appear to contribute significantly to the separation process.
3 This was indicated by the fact that the process appeared to work 4 effectively without coalescing baffles. The size distribution of water droplets in the bitumen product could explain why ths 6 baffles were not effective. These small particles may require 7 more shear energy to coalesce than could be supplied in the 8 vessel.

Claims (2)

1. A method for separating water and bitumen present in the emulsion fluid produced from a steam assisted gravity drainage process being applied to a subterranean oil sand reservoir, comprising:
retaining the fluid, in contact with an effective concentration of demulsifier, in a separator vessel operated at elevated pressure and a temperature of at least 205°C for sufficient time to effect gravity separation of the bitumen and water; and recovering a bitumen production stream containing less than about 5% by weight water and a water production stream containing less than about 2% by weight bitumen.

2. The method as set forth in claim 1 wherein:
the separator vessel is operated at a temperature of about 215°C; and the fluid is retained in contact with an effective concentration of reverse emulsion breaker.