CA2901786A1 - Paraffinic froth treatment - Google Patents

Abstract

Disclosed is a process including feeding a diluted bitumen froth into a settler to form a hydrocarbon-rich layer and a water-rich layer, and an interface layer therebetween, and raising and lowering the interface layer by controlling diluted bitumen froth feeding, underflow outflow, or overflow outflow, or a combination thereof, for improving separation.

Description

PARAFFINIC FROTH TREATMENT
BACKGROUND
Field of Disclosure [0001] The disclosure relates generally to the field of oil sand processing. More specifically, the disclosure relates to processing bitumen froth.
Description of Related Art

[0002] This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0003] Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface formations that can be termed "reservoirs." Removing hydrocarbons from the reservoirs depends on numerous physical properties of the subsurface formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subsurface formations, and the proportion of hydrocarbons present, among other things.
Easily harvested sources of hydrocarbons are dwindling, leaving less accessible sources to satisfy future energy needs. As the costs of hydrocarbons increase, the less accessible sources become more economically attractive.

[0004] Recently, the harvesting of oil sand to remove heavy oil has become more economical. Hydrocarbon removal from oil sand may be performed by several techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot air, solvents, or a combination thereof, can be injected to release the hydrocarbons. The released hydrocarbons may be collected by wells and brought to the surface. In another technique, strip or surface mining may be performed to access the oil sand, which can be treated with water, steam or solvents to extract the heavy oil. Where the oil sand is treated with water, the technique may be referred to as water-based extraction (WBE). WBE is a commonly used process to extract bitumen from mined oil sand.

[0005] In an example of WBE, mined oil sands are mixed with water to create a slurry suitable for extraction. Caustic may be added to adjust the slurry pH to a desired level and thereby enhance the efficiency of the separation of bitumen.

[0006] Regardless of the type of WBE employed, the extraction process will typically result in the production of a bitumen froth comprising bitumen, water and fine particles and a tailings stream comprising coarse particles and some fine particles and water.
The tailings stream may consist essentially of coarse particles and some fine particles and water. A typical composition of bitumen froth may be about 60 weight (wt.) % bitumen, 30 wt. %
water, and wt. % solids. The water and solids in the froth are considered as contaminants. The contaminants may be substantially eliminated or. reduced to a level suitable for feed to an oil refinery or an upgrading facility, respectively. Elimination or reduction of the contaminants may be referred to as a froth treatment process. Elimination or reduction of the contaminants may be achieved by diluting the bitumen froth with a solvent. The solvent may comprise any suitable solvent, such as an organic solvent. For example, the organic solvent may comprise naphtha solvent and/or paraffinic solvent. Diluting the bitumen with solvent (also referred to as dilution) may increase the density differential between bitumen and water and solids.
Diluting the bitumen with solvent may enable the elimination or reduction of contaminants using multi-stage gravity settlers. Use of the multi-stage gravity settlers may result in a "diluted bitumen froth" and froth treatment tailings. The froth treatment tailings may comprise residual bitumen, residual solvent, solids and water. The froth treatment tailings may be further processed to recover residual solvent, for instance in a tailings solvent recovery unit (TSRU).

[0007] Certain processes use naphtha to dilute bitumen froth before separating the product bitumen by centrifugation. These processes are called naphthaneic froth treatment (NFT) processes. Other processes use a paraffinic solvent, and are called paraffinic froth treatment (PFT) processes, to produce pipelineable bitumen with low levels of solids and water. In the PFT process, a paraffinic solvent (for example, a mixture of iso-pentane and n-pentane) is used to dilute the froth before separating the product, diluted bitumen, by gravity.
A portion of the asphaltenes in the bitumen is also rejected by design in the PFT process and this rejection is used to achieve reduced solids and water levels. In both the NFT and the PFT
processes, the diluted tailings (comprising water, solids and some hydrocarbon) are separated from the diluted product bitumen.

[0008] Solvent is typically recovered from the diluted product bitumen component before the bitumen is delivered to a refining facility for further processing.

[0009] One PFT process will now be described further, although variations of the process exist. The PFT process may comprise at least three units: Froth Separation Unit (FSU), Solvent Recovery Unit (SRU) and Tailings Solvent Recovery Unit (TSRU).
Two FSUs may be used, as shown in Fig. 1.

[0010] With reference to Fig. 1, mixing of solvent with the feed bitumen froth (100) is carried out counter-currently in two stages: FSU-1 and FSU-2, labeled as Froth Separation Unit 1 (102) and Froth Separation Unit 2 (104). The bitumen froth comprises bitumen, water, and fine solids (also referred to as mineral solids). A typical composition of bitumen froth is about 60 wt% bitumen, 30 wt% water, and 10 wt% solids. The paraffinic solvent is used to dilute the froth before separating the product bitumen by gravity. Examples of paraffinic solvents are pentane or hexane, either used alone or mixed with isomers of pentanes or hexanes, respectively. An example of a paraffinic solvent is a mixture of iso-pentane and n-pentane. In FSU-1 (102), the froth (100) is mixed with the solvent-rich oil stream (101) from the second stage (FSU-2) (104). The temperature of FSU-1 (102) is maintained at, for instance, about 60 C to about 80 C, or about 70 C, while the solvent to bitumen (SB) ratio may be from 1.4:1 to 2.2:1 by weight or may be controlled around 1.6:1 by weight for a 60:40 mixture of n-pentane:iso-pentane. The overhead from FSU-1 (102) is the diluted bitumen product (105) (also referred to as the hydrocarbon leg) and the bottom stream from FSU-1 (102) is the tailings (107) comprising water, solids (inorganics), asphaltenes, and some residual bitumen. The residual bitumen from this bottom stream is further extracted in FSU-2 (104) by contacting it with fresh solvent (109), for instance, in a 25 to 30:1 (w/w) SB ratio at, for instance, about 80 C to about 100 C, or about 90 C. Examples of operating pressures of FSU-1 and FSU-2 are about 550 kPag and 600 kPag, respectively. The solvent-rich oil (overhead) (101) from FSU-2 (104) is mixed with the fresh froth feed (100) as mentioned above. The bottom stream from FSU-2 (104) is the tailings (111) comprising solids, water, asphaltenes and residual solvent, which is to be recovered in the Tailings Solvent Recovery Unit (TSRU) (106) prior to the disposal of the tailings (113) in an ETA. The recovered solvent (118) from TSRU (106) is directed to the solvent storage (110).
Solvent from the diluted bitumen overhead stream (105) is recovered in the Solvent Recovery Unit (SRU) (108) and passed as solvent (117) to Solvent Storage (110). Bitumen (115) exiting the SRU
(108) is also illustrated. The foregoing is only an example of a PFT process and the values are provided by way of example only. An example of a PFT process is described in Canadian Patent No. 2,587,166 to Sury.

[0011] It would be desirable to provide an alternative or improved process for treating bitumen froth.
SUMMARY

[0012] It is an object of the present disclosure to provide alternative or improved methods for processing bitumen froth.

[0013] Disclosed is a process including feeding a diluted bitumen froth into a settler to form a hydrocarbon-rich layer and a water-rich layer, and an interface layer therebetween, and raising and lowering the interface layer by controlling diluted bitumen froth feeding, underflow outflow, or overflow outflow, or a combination thereof, for improving separation.

[0014] The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood.
Additional features will also be described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[0015] These and other features, aspects and advantages of the disclosure will become apparent from the following description, appending claims and the accompanying drawings, which are briefly described below.

[0016] Figure 1 is a prior art paraffinic froth treatment (PFT) process.

[0017] Figure 2 is a flow chart of a bitumen froth processing.

[0018] Figure 3 is a schematic of a bitumen froth processing.

[0019] Figure 4 is a schematic of a bitumen froth processing.

[0020] It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.
DETAILED DESCRIPTION

[0021] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.

[0022] At the outset, for ease of reference, certain terms used in this application and their meaning as used in this context are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.

[0023] Throughout this disclosure, where a range is used, any number between or inclusive of the range is implied.

[0024] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sand. However, the techniques described are not limited to heavy oils but may also be used with any number of other reservoirs to improve gravity drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0025] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sand. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.) % aliphatics (which can range from 5 wt. % - 30 wt. %, or higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and some amount of sulfur (which can range in excess of 7 wt. %).
In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.

[0026] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API
gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.00 API (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen. The recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluid by steam, hot water flooding, or gravity is possible. The reduced viscosity makes the drainage or dissolution quicker and therefore directly contributes to the recovery rate.

[0027] "Fine particles" are generally defined as those solids having a size of less than 44 microns (m), that is, material that passes through a 325 mesh (44 micron).

[0028] "Coarse particles" are generally defined as those solids having a size of greater than 44 microns (1,im).

[0029] The term "solvent" as used in the present disclosure should be understood to mean either a single solvent, or a combination of solvents.

[0030] The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.

[0031] The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.

[0032] The term "paraffinic solvent" (also known as aliphatic) as used herein means solvents comprising normal paraffins, isoparaffins or blends thereof in amounts greater than 50 wt. %. Presence of other components such as olefins, aromatics or naphthenes may counteract the function of the paraffinic solvent and hence may be present in an amount of only 1 to 20 wt. % combined, for instance no more than 3 wt. %. The paraffinic solvent may be a C4 to C20 or C4 to C6 paraffinic hydrocarbon solvent or a combination of iso and normal components thereof. The paraffinic solvent may comprise pentane, iso-pentane, or a combination thereof The paraffinic solvent may comprise about 60 wt. % pentane and about 40 wt. % iso-pentane, with none or less than 20 wt. % of the counteracting components referred above.

[0033] In current commercial practice, each Froth Settling Unit (FSU), is operated as a continuous process. The interface level at each FSU is maintained at the same level by adjusting the flow rates of the underflow and the overflow according to the feed rate and its corresponding composition. The velocity of the process fluid is non-zero.
Therefore, hydrodynamically, some solvent will be entrained by the solids to the underflow, and some solids will be entrained by the bitumen product and solvent to the overflow.

[0034] As described herein, the settler is operated semi-continuously and the interface level of the settler(s) is adjusted during operation. Operating in this way may assist bitumen (maltene) recovery and/or reduce solvent loss. Figure 2 is a flow chart of bitumen froth processing. As seen in Figure 2, disclosed is a process including feeding a diluted bitumen froth into a settler to form a hydrocarbon-rich layer and a water-rich layer, and an interface layer therebetween (202), and raising and lowering the interface layer by controlling diluted bitumen froth feeding, underflow outflow, or overflow outflow, or a combination thereof, for improving separation (204).

[0035] Figure 3 is a schematic showing filling up of a settler (302).
Suppose that at the beginning of the process, the interface level (304) between the bitumen/solvent-rich region (306) and the water-rich region (308) is at a low level. In this instance, a flow controller (not shown) (for instance a valve or pump) for the underflow (310) is at the closed or off position.
As the froth feed (312) is introduced to the settler (302), the solids (mineral solids and asphaltene flocs) together with the water will settle towards the settler bottom due to buoyancy (higher density compared to bitumen and solvent). Consequently, the interface level rises as seen in the second (302b) and third (302c) settlers of Figure 3. This feeding and settling process may be continued until the interface level reaches a desired level, which may be below inlet pipes feeding the bitumen froth. The desired level may alternatively be above these inlet pipes. When the desired level is reached, a flow controller for the underflow is opened or turned on. This operation allows drainage of the water-rich region.
The overflow (314) is also shown, as described above.

[0036] Figure 4 is a schematic showing draining of the settler. The draining may be continued until the interface level (404) reaches a desired level in the settler. Numerals are not repeated in Figures 3 and 4 because only the interface levels change.

[0037] While no promises are made, the following potential benefits will now be discussed.

[0038] When the underflow is not flowing, the solids have the opportunity to compact in the water-rich region, creating a denser bed. As the solids compact, solvent in between the asphaltene flocs and mineral solids is squeezed out, thereby allowing the solvent to float to the overflow, enhancing the solvent recovery and reducing solvent losses.

[0039] When the underflow is not flowing, additional residence time is provided for the solvent to separate from the asphaltene flocs, mineral solids, and water.

[0040] The water-rich region is more quiescent compared to a continuous process.
Therefore, there is less flow disturbance, which causes the solids to be recycled upwards, increasing the risk of releasing settled fines to the overflow. The result may be improved solids separation.

v

[0041] By controlling the underflow flow rate, the density of the underflow can also be controlled. Therefore, one can control the separation process depending on the froth feed quality.
[00421 By increasing solvent recovery, maltene recovery may also be increased.
[0043] The paraffinic solvent may be any suitable paraffinic solvent. For instance, the paraffinic solvent may comprise greater than 50 vol % pentane.
[0044] The paraffinic solvent may have greater than 50 wt. % of n-pentane, iso-pentane, or a combination thereof, based upon total weight of the solvent.
[0045] The settler may be any suitable settler. The settler may be a froth settling unit (FSU), as described above. Where two or more separators are used, they may be arranged in series or in parallel. While the froth feed is illustrated into the side of the settler, the froth feed may also be fed into the middle of the settler and may include any suitable number of entry ports.
[0046] Underflow recirculation pumps that recycle the solids to disrupt the FSU cone bottom bed and improve hydrocarbon-water exchange may be used.
[0047] Water injection at different locations (e.g. feed barrels, cone bottom, cone boot, etc.) in the FSUs may be used.
[0048] Solvent may be recovered from the overflow to produce a bitumen product.
For example, the overflow may be passed through a solvent recovery unit (SRU) or other suitable apparatus in which the solvent is flashed off and condensed in a condenser associated with the solvent flashing apparatus and recycled/reused in the process. The SRU may be any suitable SRU, such as but not limited to a fractionation vessel. Any suitable amount of solvent may be removed.
[0049] The underflow may be sent to a second separator, for instance as described above as a second FSU. A second paraffinic solvent may be added to the underflow followed by gravity separating the underflow.

[0050] A feed time during which the diluted bitumen froth is fed into the settler may be between 5 and 120 minutes. A drain time during which the underflow is drained from the settler may be between 5 and 120 minutes.
[0051] Part of the underflow may be recycled back into the settler for improving separation. A volume ratio of diluted bitumen froth: recycled underflow may be 1:1 to 5:1.
A recirculation pump may be used for this purpose. The recirculation pump along with the flow may impart shear on the underflow being recycled, breaking up asphaltenes aggregates, and thereby releasing intra-particle solvent.
[0052] Water may be injected into a bottom cone section of the settler for improving separation. The rate of water injection may be 10 m3/hr, 30 m3/hr, 50 m3/hr, 100 m3/hr, 150 m3/hr, 200 m3/hr, or up to 250 m3/hr.
[0053] Additives may be added to the settler for lowering surface tension, breaking emulsions, or promoting release of solvent, especially during the fill process, where solids settle in the vessel.
[0054] It should be understood that numerous changes, modifications, and alternatives to the preceding disclosure can be made without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

Claims (20)

CLAIMS:

1. A process comprising:
feeding a diluted bitumen froth into a settler to form a hydrocarbon-rich layer and a water-rich layer, and an interface layer therebetween; and raising and lowering the interface layer by controlling diluted bitumen froth feeding, underflow outflow, or overflow outflow, or a combination thereof, for improving separation.

2. The process of claim 1, wherein the controlling comprises controlling the diluted bitumen froth feeding and the underflow outflow.

3. The process of claim 1 or 2, wherein the controlling comprises raising the interface level by feeding the diluted bitumen froth without significant underflow outflow, and lowering the interface layer by having an underflow outflow without significant feeding of the diluted bitumen froth.

4. The process of any one of claims 1 to 3, wherein the controlling comprises raising the interface layer to an upper height and lowering the interface to a lower height, wherein the upper height is at least twice as high as the lower height.

5. The process of claim 4, wherein the upper height is at least three times as high as the lower height.

6. The process of claim 4, wherein the upper height represents at least 50 % of a fill volume based on a height of a feeding height of the diluted bitumen froth feed inlet.

7. The process of claim 4, wherein the upper height represents at least 80 % of a fill volume based on a height of a feeding height of the diluted bitumen froth feed inlet.

8. The process of claim 4, wherein the lower height represents less than 20 % of a fill volume based on a height of a feeding height of the diluted bitumen froth feed inlet.

9. The process of claim 4, wherein the lower height represents less than 10 % of a fill volume based on a height of a feeding height of the diluted bitumen froth feed inlet.

10. The process of claim 4, wherein the upper height is higher than a feeding height of the diluted bitumen froth feed inlet.

11. The process of any one of claims 1 to 10, wherein the diluted bitumen froth comprises a paraffinic solvent.

12. The process of claim 11, wherein the paraffinic solvent comprises greater than 50 vol % pentane.

13. The process of any one of claims 1 to 12, wherein the settler is a froth separation unit.

14. The process of any one of claims 1 to 13, further comprising removing solvent from the overflow to form a bitumen product.

15. The process of claim 11, further comprising adding a second paraffinic solvent to the underflow and then gravity separating the underflow.

16. The process of any one of claims 1 to 15, wherein a feed time during which the diluted bitumen froth is fed into the settler is between 5 and 120 minutes.

17. The process of any one of claims 1 to 16, wherein a drain time during which the underflow is drained from the settler is between 5 and 120 minutes.

18. The process of any one of claims 1 to 16, further comprising recycling part of the underflow back into the settler for improving separation.

19. The process of any one of claims 1 to 16, further comprising injecting water into a bottom cone section of the settler for improving separation.

20. The process of any one of claims 1 to 16, further comprising adding additives to the settler for lowering surface tension, breaking emulsions, or promoting release of solvent.