DK174491B1 - Mfg. hydrocarbon material esp. heavy crude oil or bitumen - for further processing by emulsifying in water, degassing, breaking the emulsion and re-emulsifying with water - Google Patents

Abstract

Prepn. of a naturally occurring viscous hydrocarbon material for further processing comprises: (a) with an emulsifier, forming a 1st hydrocarbon-in-water emulsion (I) with H2O content at least 15 wt.%, max, viscosity 5000 cP at 122 deg. F and max. oil droplet size 300 microns; (b) degassing emulsion (I) at a temp. as low as 95 deg and min pressure 20 psi with min. degassing efficiency 90%, to produce an emulsion (II) contg. less than 5 cu. ft./bbl. of gas; (c) adjusting the density difference between the phases of emulsion (II) to be at least 0.002 g/cc at temp. T which is at least equal to 15 deg.C below the cloud point of the emulsifier used in (a); (d) breaking the density-adjusted emulsion (III) in a separator at temp. T, and recovering the hydrocarbon material; (e) re-emulsifying the hydrocarbon material using an emulsifier, and conditioning it for further processing so as to form a 2nd stable hydrocarbon emulsion (IV) suitable for transportation; and (f) transporting emulsion (IV). Breaking a hydrocarbon-in-water emulsion comprises essentially steps (c), (d) and (e) of (A).

Description

1 DK 174491 B1

The prior art

The most relevant related prior art which deals with the formation of hydrocarbon-in-water emulsions from viscous hydrocarbons and for use as a combustible fuel is disclosed in GB Patent 974,042 and US Patent 4,618,348. Further patents in which prior art relates, which prior art relates to combustion of hydrocarbon / water emulsions of the oil-in-water (o / v) and water-in-oil (v / o) type, are U.S. Patent 3,958,915 , 4,273,611,4,382,802, 3,352,109, 3,490,237, and 4,084,940.

10

Relevant patents in which prior art relates, which prior art is concerned with the formation and transport of hydrocarbon-in-water emulsions, are the following: US Patent Nos. 3,380,531, 3,487,844, 3,006,354, 3,425,429, 3,467,195, 4,239,052 and 4,249,554.

15

Other prior art dealing with o / v and / or v / o type emulsions are the following: RE Barrett et al., "Design, Construction and Preliminary Combustion Trials of a Rig to Evaluate Residual Fuel-Oil / Water Emulsions", July 15, 1970, Battelle Μ. I., Columbus, Ohio, PB-214260, VGB Kraftwerkstechnik, Vol. 55, 2, 20 1975, R. Helion et al., "Reduction of Flue Gas Emissions by Burning Fuel-Oil

Water Emulsions ", pages 88-93 (59-Air Pollution, Ind. Hyg., Vol. 84.1976, page 335, no. 84: 78995g), JP Publication Writing 77-151,305 published December 15, 1977 and based on application no. 76 / 68,530 filed on June 11, 1976 with N. Moriyama et al as inventors and entitled "Emulsifying 25 Agents for Oil-in-Water Type Emulsions" (51-Fossil Fuels, Vol. 80,1978, page 145, no. 89: 8710q), Nenryo Kyokaishi, Vol. 58, 632, 1979, JP, A. Iwama, "Single Droplet Combustions of Emulsified Hydrocarbon Fuels. II. Comparison of Combustion Characteristics Between O / W and W / O Emulsions ", pages 1041-54 (Chemical Abstracts, Vol. 93, 1980, page 204, No. 93: 50075u), Rosenberg et al.," Interaction of Acinetobacter RAG 1, Emulsan with Hydrocarbons "in M. Moo-Young, editor," Advances in Biotechnolgy, Volume III, Fermentation Products ", 1981, Proceedings of the Vlth International Fermentation Symposium held in DK 174491 B1

London, CA, July 20-25, 1980, pages 461-466, "Osaka Kogyo Gijutsu Shikensho Kiho", Vol. 23, 3, 1972, Y. Murakami et al., "Burning of Emulsified Oil Waste" (Chemical Abstracts , Volume 78, page 222, No. 61800t), DD patent 93,398 of October 20, 1972 based on Application No. 148,658 of July 8, 1978, with H. Lude-5 wig as the inventor and entitled "Hydrocarbon-Emulsifier-Water Emulsion. "(Chemical Abstracts, Vol. 80, 1974, page 150, No. 85531 y), K. Enzmann et al.," Preparation of Fuel Oil-ln-Water Emulsions for Combustion ", 1980, Universal'n Dezintegrator Aktivatsiya Tallin, page 82-6, (Russian language) from Ref. Zh. Khim, 1980, abstr. No. 14P334 (51-Fossil Fuels, Vol. 93, 1980, page 147, no.

10 93: 170678q), DD patent 216,863 of January 2, 1985 based on application no.

253,527 of July 29, 1983 with O. Neumeister et al. as inventors and entitled "Method and apparatus for Preparing Fuel-Water Emulsions" and R.

E. Barrett et al., "Residual Fuel Oil-Water Emulsions," January 12, 1970, Battelle M.

I., Columbus, Ohio, PB-189076.

15

The invention relates to a method for recovering and / or working up a viscous hydrocarbon material and conditioning this viscous hydrocarbon material in the form of a hydrocarbon-in-water emulsion for further processing.

20

High density, viscous hydrocarbons present in CA, SU, US, CN and VE are usually liquid with viscosities ranging from 10,000 to more than 500,000 mPa * s at ambient temperatures and densities which is greater than 0.986 g / cm3. These 25 hydrocarbons are currently produced either by injection of steam combined with mechanical pumping or mechanical pumping per se or by refractive engineering. Due to the nature of the viscous hydrocarbon materials, their use in today's market is limited. In order to develop these resources commercially, it is highly desirable to provide methods for extracting, reprocessing and transporting the viscous hydrocarbons so that they are commercially useful as raw material for the production of various products and / or applications.

OBJECTS OF THE INVENTION Accordingly, it is a principal object of the invention to provide methods for the formation, processing, and transport and end use of a hydrocarbon-in-water emulsion.

Further purposes and benefits will appear below.

10

The invention relates to a method of extracting, processing, transporting and using viscous hydrocarbons. The term "viscous hydrocarbon" as used herein means any naturally occurring crude oil or bitumen characterized by a viscosity greater than or equal to 100 15 mPa * s at a temperature of 50.2 ° C. , a density equal to or greater than 0.959 g / cm3, a high metal content, a high sulfur content, a high asphaltene content and / or a high flow point, during the production of naturally occurring crude oil or bitumen, thereby producing water containing elements that are undesirable in the final emulsified product.

20

Further, the invention includes a process for recovering a naturally occurring viscous hydrocarbon material for further workup, comprising the steps of (a) forming a first hydrocarbon-in-water emulsion from said naturally occurring viscous hydrocarbon material under using an emulsifier, said hydrocarbon-in-water emulsion being characterized by a water content of at least 15 wt%, a viscosity of not more than 5,000 mPa * s at 50.2 ° C and an oil droplet size of not more than 300 and (b) degassing - if necessary - of said first hydrocarbon-in-water emulsion at a temperature as low as 35.0dC and at a pressure of at least 137.9 kPa to obtain a degassing efficiency for said hydrocarbon-in-water emulsion greater than or equal to 90%, to produce a degassed hydrocarbon-in-water emulsion having a gas content p less than 0,891 std. 1 gas per 1 primary emulsion, preferably less than 0.356 hours. 1 gas per 1 primary emulsion.

5 The drawing

The invention will now be described in more detail with reference to the drawing, in which: FIG. 1 is a schematic illustration of the flowchart of the manufacturing process of the invention in its entirety; FIG. 2 is an illustration of a first embodiment of forming a hydrocarbon-in-water emulsion; and FIG. 3 is an illustration of another embodiment of forming a hydrocarbon-in-water emulsion.

Description of an Example 20

The invention relates to a method for recovering a viscous hydrocarbon material from natural beds and conditioning this viscous hydrocarbon material in the form of a hydrocarbon-in-water emulsion for further processing.

In practice, an oil field comprises a large number of deep wells for removing viscous hydrocarbons from the subsurface. Depending on the nature of the oil trap, various lifting mechanisms can be used to recover the viscous hydrocarbon. For example, in some wells a vapor injection may be made to permeate the oil trap, the purpose of this soaking being to assist in the recovery and lifting of the viscous material by mechanical pumping. It may happen that in other oil traps, in all its simplicity, only a pump for deep wells is needed, while it may happen that in other oil traps it is convenient to make the downhole of hydrocarbon-in-oil. water emulsions to lift the viscous material. In most cases, a combination of these methods is desirable. According to the invention, it is desirable to form the emulsion as close to the well as possible to obtain the viscosity advantage of the emulsion.

FIG. 1 is a simplified schematic illustration of the flow diagram of a production plant according to the invention from well to end user. In the plant 10 10, a large number of operating wells 12, equipped with pumps 14 for deep wells or the like, are used to extract the naturally occurring viscous hydrocarbon material from the subsurface. The viscous material for which the invention is determined is characterized by the following chemical and physical properties: C wt% of 78.2-85.5, H wt% of 9.0-10.8, O wt% of 0.26-1, 1, 15 N wt% of 0.50- 0.70, S wt% of 2.00-4.50, ash wt% of 0.05-0.33, vanadium ppm of 50-1,000, nickel ppm 20-500, iron ppm 5-100, sodium ppm 10-500, density 0.959 g / cm3 to approx. 1.6 g / cm 3, viscosity (mm 2 / s) at 50.2 ° C of 100-5000,000, viscosity (mm 2 / s) at 99 ° C of 10-16,000, LHV (kJ / kg) of 34, 92 x 103 to 44.23 x 10 3 and asphaltenes wt% of 5.0 - 25.0. The viscous material extracted from the well is fed to a flow station 16 where the material from all the wells is collected. The assembled material can then be passed on for further processing in a degassing unit 20. A static mixing device 18 is provided prior to the degassing unit taken in the flow direction to ensure that a homogeneous hydrocarbon-in-water e-25 feed is fed to the degassing unit. According to the invention, the degassed primary emulsion is then broken into a device 22 and then recovered in a device 24 and conditioned for a particular end use. The emulsifiers 26 from a device thereto and the additives 28 from a device thereto used in the recovery are determined by the particular end use of the emulsion, such as will be described below. The stable recovered emulsion is transported 30 in a device thereto for firing 32 in a device thereto or for further refining 34 in a device thereto. As noted above, breaking the primary emulsion and restoring the commercial ORIMULSION (R) product is a crucial feature of the invention. As noted above, a water formation is produced along with the natural bitumen and / or crude oil and as a result it is difficult to control the emulsion characteristics at the well site. By breaking the primary emulsion, the ORIMULSION (R) product can then be formed and conditioned depending on the end use of the product. The water and emulsifier recovered from the quenching step of the process can be recirculated via line 36 to form the primary well emulsion at the well site or, if appropriate, partially used in the recovery step.

According to the invention, the material fed to the degassing unit for further processing should be in the form of a hydrocarbon-in-water emulsion having the following characteristics: A water content of at least 15% by weight, a viscosity of 5,000 mPa , 2 ° C and a droplet size of not more than 300 µm. It has been found that hydrocarbon-in-water emulsions having the foregoing characteristics can be effectively degassed. If the emulsion viscosity is greater than 5,000 mPa · s at 50.2 ° C, the gas cannot efficiently escape. Likewise, if the size of the oil droplet exceeds 300 µm, the gas is trapped as in a trap inside the droplet, thereby reducing the efficiency of degassing.

The process of the invention is devised to ensure that a proper emulsion is fed to the degassing unit for further processing. According to the invention, the emulsion can be formed at a number of locations depending on the nature of the well and the viscous hydrocarbon produced. Initial formation of the emulsion can occur downhole, at the well's head, in the flow station, or in any combination of these three options. For example, if steam has been injected into a well's oil trap, the temperature of the dead oil may be so high just after soaking with the steam cycle that it is impossible to effectively form an downhole emulsion. In other cases, the viscosity of the crude oil is such that pumping to the flow station without injection of steam or emulsion formation can be considered. In addition, the product from the individual wells will vary in terms of oil and gas content, the extent of water formation and salt concentration. Therefore, the formation of the various 5 emulsions must be controlled to ensure that a homogeneous, emulsified product having the above characteristics is finally prepared to be fed to the degassing unit. It is preferred to form the emulsion as close to the well as possible to take advantage of the viscosity change.

According to the invention, the hydrocarbon-in-water emulsion is formed by mixing a mixture of water plus emulsifier with the viscous hydrocarbon. As noted above, the formation of the emulsion in an oil field manufacturing plant can be done downhole, at the wellhead, in the flow station, or in any combination of these three options. The preferred 15 emulsifier additives are selected from the group consisting of nonionic surfactants, nonionic surfactants plus polymers and / or biological agents of biological origin and nonionic surfactants plus ionic surfactants consisting of anionic and cationic surfactants, and nonionic surfactants combined with 20 alkalis. The preferred nonionic surfactants include ethoxylated alkyl phenols, ethoxylated alcohols and ethoxylated sorbitan esters. Suitable polymers for use with nonionic surfactants include, for example, polysaccharides, polyacrylamides and cellulose derivatives.

Suitable surfactants of biological origin or biopolymers include 25 rhamnolip and xanthan gums. Cationic surfactants are selected from the group consisting of quaternary ammonium compounds, ethoxylated amines, amidoamines and mixtures thereof. Anionic surfactants include long chain carboxylic and sulfonic acid salts, sulfates and mixtures thereof.

Alkali, such as ammonia and monovalent hydroxides or mixtures thereof, are preferred in combination with nonionic surfactants. According to the invention, the preferred nonionic surfactant alkylphenol ethoxylate having an EO content greater than or equal to 70%. If the EO content is less than 70%, there is a tendency for water-in-hydrocarbon emulsions to form. To illustrate the above, six emulsions were prepared from Cerro Negro crude oil with a density of 0.985 g / cm3 using three different nonionic surfactants: an alkyl phenol ethoxylate having an EO content of 78%, 74%, respectively. 66%. The compositions of the emulsions and physical characteristics are listed in Table I.

Table I

10

Emul-% EO in Wife. Oil / Dannel Medium Emulsion over water system small sion surface surface temperature drop type active surface hold T, ° C diam.

15 medium active (v / v) pm average ppm # 1 78 2,000 60/40 40 39 rpm 20 # 2 78 2,000 80/20 60 40 rpm # 3 74 2,000 60/40 40 47 rpm 25 # 4 74 2,000 60/40 60 61 rpm # 5 66 2,000 60/40 40 58 rpm # 6 66 2,000 60/40 60 rpm

As can be seen from Table I, the diameter of the oil droplet grows as the EO content of the emulsifier decreases. Likewise, the size of the oil droplet, as the temperature rises and the oil content of the emulsion, increases. Emulsion # 6 could not form as a hydrocarbon-in-water emulsion due to the low EO content of the emulsifier, but on the contrary resulted in a water-in-oil emulsion.

5

It has been found that the addition of salt has an effect on the emulsion formation in that the addition of salt enables a reduction in the concentration of the surfactant while maintaining the necessary emulsion characteristics. To illustrate the foregoing, six emulsions were formed using Hamaca crude oil having a density of 0.9965 g / cm 3 and using the preferred nonionic surfactant of the present invention, namely an alkylphenole oxylate having an E content of 78%. Salt in the form of NaCl was added to the aqueous phase in three of the emulsions. The composition and physical properties of the emulsions are listed in Table II.

15

Table II

Emul% EO in NaCl cone. Oil / Dannel- Medium-Typesion Overflow. of water system- small of 20 surface ppm over-temperature drop emulsion-active surface hold T, ° C diam. sion agent active (v / v) pm average ppm 25 # 1 78 - 1,500 60/40 25 63 o / v # 2 78 - 1,000 60/40 25 67 o 30 # 3 78 - 500 60/40 25 73 o / v # 4 78 20,000 1,500 60/40 25 68 rpm # 5 78 20,000 1,000 60/40 25 66 rpm 10 DK 174491 B1 # 6 78 20,000 500 60/40 25 65 rpm

From Table II, it is clear that the addition of salt does not have a detrimental effect on emulsion formation and oil droplet size.

Furthermore, it has been found that when using a biopolymer in combination with the nonionic surfactant preferred in the present invention, the required amount of surfactant is reduced to form the desired emulsion. The foregoing is shown in Table III when a xanthan gum species is used as a biopolymer.

Table III

Emul-% EO in Wife. Wife. Oil / Dannel-Medium Typesion of water system-small of surface-over-bio-temperature drop emulsion-20 active surface polyethylene T, ° C diam. sion agent active more (v / v) pm average ppm ppm 25 # 1 78 500 500 60/40 40 41 rpm # 2 78 230 200 60/40 40 66 rpm # 3 78 230 - 60/40 40 v / free 30 crude oil # 4 78 150 - 60/40 40 v / o ^ DK 174491 B1

As can be seen from Table III, the biopolymer supports the formation of the emulsion. The emulsion # 3 above contained free crude oil and is therefore unsuitable for the purposes of the invention.

Table IV shows the properties obtained by using alkalis with or without salt addition to form emulsions containing Cerro Negro crude oil with a density of 0.985 g / cm 3. The alkali 10 used was NH 4 OH.

Table IV, Part 1

To-pH NaCl-Oil / Dannel-Medium-Type-Set Wife. water sys- tem of recovery ppm temperature drop emulsifier hold T, ° C diam. sion (v / v) pm 20 NH4OH 9.5 - 70/30 40 - Ί. e.

NH4OH 11.0 - 70/30 40 57 o / v NH4OH 11.4 - 70/30 40 27 o 25 v NH4OH 12.0 - 70/30 40 - v / o NH4OH 9.5 - 70/30 60 - ie

30 NH4OH 11.2 - 70/30 60 66 o / v NH4OH 11.4 - 70/30 60 33 o / o NH4OH 12 - 70/30 60 - v / o 12 DK 174491 B1 NH4OH 10.6 10,000 70/30 40 - ie

5 NH4OH 11.1 10,000 70/30 40 44 o / v NH4OH 11.2 10,000 70/30 40 - o / o NH4OH 9.5 - 74/26 25 - i. E.

NH4OH 12.9 - 74/26 25 - i. E.

Table IV, Part 2

To-pH NaCl-Oil / Dannel-Medium-Type-Set Wife. water sys- tem of recovery ppm temperature drop emulsifier hold T, ° C diam. sion (v / v) pm 20 NH4OH 9.5 - 74/26 40 - i. e.

NH4OH 12.5 - 74/26 40 - i. E.

NH4OH 9.5 - 74/26 60 - i. E.

NH4OH 12.5 - 74/26 60 - i. E.

NH4OH 9.5 10,000 74/26 60 - i.

30 NH4OH 12.5 10,000 74/26 60 - i.

* i.e. is an abbreviation of no emulsion.

13 DK 174491 B1

As can be seen from Table IV, the added amount of NH 4 OH is essential for the formation of the desired emulsion. To form the emulsion, NH 4 OH must be added in an amount sufficient to regulate the pH of the emulsion to a level of 10 * 12, with 11-11.5 being preferred. Furthermore, it can be seen that high salt levels have a detrimental effect on emulsion formation.

It has been found that the use of a small concentration of the preferred nonionic surfactant used in combination with the NH 4 OH additive greatly improves the pH range in which useful emulsions are formed. Table V shows the results for emulsions prepared using the Cerro Negro crude oil associated with Table IV.

Table V

15 To-% EOi Conc. pH Oil / Dannel- Medium- Type-set- of water system- small- of surface- surface- over- drop droplet emulsifier active surface holding T, ° C diam. sion agent active (v / v) pm 20 average ppm NH4OH 78 250 9.9 74/26 40 70 u 25 NH4OH 78 250 11.3 74/26 40 23 u NH4OH 78 250 12.3 74/26 40 - w / o NH4OH 78,500 9.9 74/26 40 60 w / o NH4OH 78,500 11.3 74/26 40 24 w / o NH4OH 78,500 12,3 74/26 40 - w / o NH4OH 78 1,000 9.9 74/26 40 48 rpm DK 174491 B1 NH4OH 78 1,000 12.3 74/26 40 68 rpm Once again, it is found that when alkali is used in combination with a nonionic surfactant suitable emulsions can be prepared.

The foregoing examples show the effect of various additives on the emulsion formation. Depending on the dietary nature of many surfactants, it is greatly beneficial to limit the concentration of surfactant additives.

According to the invention, the emulsion when prepared at the well site can be prepared in a manner as illustrated schematically in FIG. 2 and 3. For example, as illustrated in FIG. 2, the emulsifier plus water can be injected downhole via conduit 42 into well casing 44 below the submersible pump 46 to form the emulsion pumped up through the conduit 48. A static mixing device 50 can be used in the delivery conduit 52 and it is purely preferred. in fact, for homogenizing the emulsion delivered from the production tube 48. Table VI lists the results obtained by downhole emulsion formation according to the system of FIG. 2 with or without the use of static mixer 50. The emulsifier used was the nonionic surfactant preferred in the present invention, namely an alkyl phenol ethoxylate. The density of crude oil was greater than 0.959 g / cm 3.

25

Table VI

Sta- flow% H20 Wife. Medium Eff.

tical of small% 30 bian- speed-drop surface diam.

device 1 / day active pm 15 pm 174491 B1 medium ppm

No 32,910 49 3,400 5

No 41,970 42 2,600 51 78 j No 45,310 40 2,500 10

Yes 42,450 31 2,800

Yes 50,081 29 2,200 42 74 15 Yes 47,308 30 2,400

As can be seen from Table V, the use of a static mixing device results in a smaller particle size emulsion. Suitable static mixing devices for this purpose include, for example, mixing devices manufactured by Sulzer Bros. and sold under the SULZER trademark.

FIG. 2 illustrates an alternative downhole emulsification system, the emulsifier water solution being injected via line 42 'into well casing 44' above 25 pump 46 ', and emulsion up through production tube 48' and out through supply line 52 'which may be provided with a static mixing device 50 '.

Table VII lists the results obtained using the system of FIG. 2, using the same surfactant and crude oil for which comments have been made above.

30

Table VII

Sta- Press Dan- Power% H20 Wife. Medium Eff.

16 DK 174491 B1 tical kPa crop of small% bias rate droplet droplet depth flat diam.

device per 1 day active pm 5 hourly average ° C ppm

No 359 33.3 44.040 42 6.109 200 52 10 No 359 33.3 41.970 47 6.313 200

Yes 669 32.8 33.230 47 3,846 15 Yes 593 30.6 34.660 38 3.661 63 43

Yes 490 34.4 40.060 40 3.190 20 Again, it is seen that the use of a static mixing device improves the droplet size of the oil droplets. Furthermore, it can be seen that the system does not lead to the formation of small emulsion droplet sizes, just as the pumping efficiency is lower.

A further alternative to downhole emulsions is shown in FIG. 3, wherein the solution of the surfactant and water is injected into the pump housing between the stationary valve and the moving valve, see the pending application with serial number. 095,569 (agent's case number 86-328), incorporated herein by reference. Referring to FIG. 3, the emulsifier solution is injected via conduit 42 "into well casing 44" through a feed valve 54 into pump housing 56 where it is mixed with the crude oil to form an emulsion. The emulsion is pumped up through the production tube 48 "and out through the supply line 52". Once again, a static mixer 50 "may be provided closest to the wellhead. Table VIII lists the emulsions obtained using the system of Fig. 3.

Table VIII 5

Sta- Press Dan- Power% H20 Wife. Medium Eff.

tical kPa counting of small% bias velocity- drop droplet depth flat diam.

10 device per 1 day active reaction at medium ° C ppm

No. 345 32.2 45,310 40 2,400 15

No 276 34.4 42.610 42 3.400 45 88

No. 310 35 46,900 39 3,100 20

Yes 345 34.4 48,650 31 3,100

Yes 407 33.9 40.380 35 3.600 46 85 25 Yes 359 37.8 37.040 40 2.400 In this case, the static mixing device did not improve the particle size of the emulsion; however, the efficiency of this system is higher.

In each of the systems illustrated in FIG. 2 and 3, the emulsion may be prepared by injecting the emulsifier-water solution at the wellhead via line 28 prior to static mixing device 20 taken in the flow direction, rather than downhole. Table IX lists the results obtained for such a system where the emulsion is formed at the wellhead using a static mixing device.

Table IX

Current% H20 Wife. Medium Eff.

speed drop 10 flat diam.

1 / day active pm average ppm 15 45,150 36 4,600 52,620 37 2,000 58 55%.

45,470 35 2,300 20 47,700 28 2,200

As can be seen from Table IX, although the droplet size in the emulsion is perfectly acceptable, the well efficiency is not as good as in the other systems.

From the foregoing, it is seen that the system of FIG. 3 is preferred.

The product from the production wells is delivered - either in the form of a hydrocarbon-in-water emulsion or in another form - via production lines to the flow station where they are collected. The volume of the crude oil being pumped from the well can be calculated in known manner. Ideally, the amount of emulsifier and water added to individual wells in a field is controlled so as to obtain the correct oil / water ratio and emulsifier concentration in the flow station, thereby providing the correct emulsion characteristics with respect to the above. degassing is safe. This product is called the primary hydrocarbon-in-water emulsion. If necessary, additional emulsifier may be added to the flow station.

5

According to the invention, the primary emulsion is fed from the flow station to the degassing unit through a static mixing device. The static mixing device ensures that a homogeneous hydrocarbon-in-water emulsion is fed to the degassing unit. As previously noted, the emulsion fed to the degassing unit must have the following characteristics and properties: A water content of at least 15% by weight, a viscosity of not more than 5,000 mPa * s at 50.2 ° C and a droplet size at no more than 300 pm. By degassing a hydrocarbon-in-water emulsion, a greater degassing efficiency is achieved at lower degassing temperatures than the 15 degassing efficiencies obtainable in the prior art. Ninety percent degassing efficiency is desired. To show the foregoing, Cerro Negro crude oil with a density of approx. 0.985 g / cm 3 degassed in the conventional manner using a diluent and compared to the degassing of a hydrocarbon-in-water emulsion of the same crude oil in the conventional manner.

The results are listed below in Table X.

Table X, Part 1

Formation P% dilution% H2O Eff.,% 25 systemic solvent

perature ° C

60 483 28 - 71 30 60 414 29 - 83 20 DK 174491 B1 60 345 29 - 91 71.1 483 27 - 74 5 71.1 414 29 - 87 71.1 345 30 - 96 82.2 483 30 - 77 10 82.2 414 29 - 92 82.2 345 30 - 97 15 35 414 - 36.8 88 35 207 - 56.0 87 35 414 - 33.0 90 20 48.9 379 - 32.0 90 48.9 276 - 38.0 94 25 Table X, Part 2

Formed - P% dilution% H2O Eff.,% System sealant

temperature 30 ° C

48.9 414 - 34.0 91 60 379 - 35.0 91 21 DK 174491 B1 60 276 - 40.2 94 60 414 - 35.6 91 5 71.1 379 - 36.3 93 71.1 276 - 37.3 95 10 From the foregoing, it can be seen that the oil-in-water emulsion can be degassed effectively at much lower temperatures than diluted crude oil. Since the use of diluents and elevated temperatures adds cost to the degassing operation, degassing of emulsions is preferred.

According to the invention, the degassed primary emulsion emanating from the degassing unit is pumped to a main station or terminal where the emulsion is broken and then recovered and refilled depending on the end use of the crude oil or bitumen, be it for refinery use or direct combustion.

20

Claims (10)

22 DK 174491 B1 A method of recovering a naturally occurring viscous hydrocarbon material for further processing, characterized in that the process comprises the steps of (a) forming a first hydrocarbon-in-water emulsion from said naturally occurring viscous hydrocarbon material. using an emulsifier, said hydrocarbon-in-water emulsion being characterized by a water content of at least 15% by weight, a viscosity of not more than 5,000 mPa * s at 50.2 ° C and an oil droplet size of no more and (b) degassing said first hydrocarbon-in-water emulsion at a temperature as low as 35.0 ° C and at a pressure of at least 207 kPa to obtain a degassing efficiency for said hydrocarbon-in-water emulsion greater than or equal to 90% to produce a degassed hydrocarbon-in-water emulsion having a gas content of less than 0.891 l gas per In emulsion. Process according to claim 1, characterized in that the process comprises forming part of said first hydrocarbon-in-water emulsion downhole. Process according to Claim 1, characterized in that the method includes that part of said first hydrocarbon-in-water emulsion is formed at the wellhead. Method according to claim 3, characterized in that the method includes providing a static mixing device at the wellhead to form a homogeneous hydrocarbon-in-water emulsion. The method according to claim 1, characterized in that i The process includes combining said emulsion and feeding said composite emulsion to a static mixing device to form a homogeneous hydrocarbon-in-water emulsion prior to degassing said hydrocarbon-in-water emulsion. 5 Process according to claim 1, characterized in that the process comprises providing an emulsifier to form said first hydrocarbon-in-water emulsion selected from the group consisting of non-ionic surfactants, polymers, biological origin surfactants, cationic surfactants, anionic surfactants, alkalis and mixtures thereof. Method according to claim 6, characterized in that the process comprises providing an emulsifier to form said first hydrocarbon-in-water emulsion selected from the group consisting of ethoxylated alkyl phenols, ethoxylated alcohols, ethoxylated sorbitan esters and mixtures thereof. Method according to claim 1, characterized in that the process comprises injecting said emulsifier and water below the submersible pump to form the emulsion. Method according to claim 8, characterized in that the process includes injecting said emulsifier and water above the submersible pump to form the emulsion. Method according to claim 8, characterized in that the process includes injecting said emulsifier and water below the submersible pump into the pump housing between the stationary valve and the moving valve to form the emulsion.