US20100258477A1

US20100258477A1 - Compositions and processes for separation of bitumen from oil sand ores

Info

Publication number: US20100258477A1
Application number: US12/422,417
Authority: US
Inventors: Jari-Jukka Kukkonen; Eero Aitta; Pekka Oinas; Kaj Jansson; Mohan Nair
Original assignee: Kemira Chemicals Inc
Current assignee: Kemira Chemicals Inc
Priority date: 2009-04-13
Filing date: 2009-04-13
Publication date: 2010-10-14
Also published as: CA2700692A1; CA2700692C

Abstract

Compositions and processes for separating bitumen from oil sands ore include contacting the oil sand ores with a composition including a carboxylate salt and/or acid and an aqueous liquid carrier. The carboxylate salt and/or acid is a C₁-C₇alkyl, and in one embodiment, is a monocarboxylate.

Description

BACKGROUND

The present disclosure generally relates to processes for separating oil from oil sands.
Oil sands ore (also referred to as tar sands) are a combination of clay, sand, water, and oil-rich bitumen, which is chemically similar to conventional crude oil but has a higher density (i.e., a lower American Petroleum Institute (API) gravity) and a much higher viscosity. The typical high grade ore contains about 11% by weight or more of bitumen, the rest being largely sand and clay fines. The bitumen in oil sands ore cannot be pumped from the ground in its natural state, instead the oil sands are either surface mined or subjected to in situ mining processes to extract the bitumen, which is then refined into oil. In surface mining, the oil sands ores are crushed and transported to an extraction plant where bitumen is separated from water and sand. In situ processing refers to various methods used to recover deeply buried bitumen deposits. Cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) are in-situ recovery methods, which include thermal injection through vertical or horizontal wells, solvent injection and carbon dioxide methods. Other technologies are emerging such as pulse technology and vapor recovery extraction (VAPEX).
Current processes for extracting the oil-rich bitumen from oil sands include a hot water flotation process. The hot water flotation process includes many variations but generally begins with a conditioning step. In this step, the oil sands are vigorously mixed in relatively large tumblers or conditioning drums with hot water to break up large lumps and form a slurry. A newer approach eliminates tumblers or conditioning drums altogether. After the oil sand is crushed at the mine site, it is mixed with warm water and then moved by pipeline to the extraction plant. The piping system is called hydrotransport and is configured to condition the oil sand while moving it to extraction. The water used for hydrotransport is generally cooler (but still heated) than in the tumblers or conditioning drums, further reducing energy costs.
To assist in the recovery of bitumen during conditioning, additives can be added to the slurry. For example, a basic material such as sodium hydroxide is oftentimes added in order to maintain the pH balance of the slurry slightly basic, in the range of 8.0 to 8.5. This has the effect of dispersing the oil sands and reduces the viscosity of the slurry, thereby reducing the particle size of the minerals in the oil sands. The addition of the basic material can also saponify natural surfactants within the oil sands. The natural surfactants are known to alter the surface electric charges and interfacial tensions between the different materials within the oil sand, thereby making separation less efficient and less effective. For example, it is believed that ionization of surface groups and adsorption of charged surfactants can cause increased electrostatic repulsion, which increases the disjoining pressure in the aqueous film separation of the bitumen and the solids.
Once conditioned, the slurry is screened to separate larger debris and then fed to a separation vessel, where it is allowed to separate into three layers. Additional hot water may be added. Gravity separation of the sand and rock from the slurry occurs allowing a portion of the bitumen to float to the top where it is concentrated and removed as bitumen froth. The froth typically contains 60% by weight bitumen, 30% by weight water and 10% by weight sand and clay fines. The larger sand particles and rock settle to the bottom where it is then pumped into settling basins commonly referred to as tailing pond. The intermediate portion is often referred to as the middlings, which is relatively viscous and typically contains dispersed clay particles and some trapped bitumen which is not able to rise due to the viscosity. The middlings is then exposed to froth flotation techniques to recover additional bitumen that did not float to the top during gravity separation. After which it is passed to the tailings pond.
The bitumen froth is passed to a defrother where the froth is typically heated and broken to remove air. Naptha or a paraffinic solvent may be added to cause a reduction in the density of the bitumen so as to permit centrifugation as a means for separating the bitumen from the water and solids.
It is recognized in the industry that sodium hydroxide should be used as little as possible in the hot water flotation process, having regard to the need for controlling fines and extracting bitumen from poor ores. This is because sodium hydroxide addition increases the cost of the treatment process. Also, it is known that sodium hydroxide seriously delays the settling rate of tailings (the mixture of minerals, clay and water which is left over after extraction of the bitumen). This increases the difficulty of managing the disposal of the tailings. Also, it is found that addition of sodium hydroxide beyond a certain optimum level for any particular ore does not increase bitumen production: in fact, it may reduce it.
Although the role of sodium hydroxide in bitumen froth production is not well understood, a few studies have linked it to the production of natural surfactants. It has been said that aged bitumen may be deficient in surfactants, and sodium hydroxide could cause some to be generated. However, this work has not led to any method of identifying bitumen which is lacking in such surfactants, or to any practical process of treating such ores. Further, the amount of sodium hydroxide which is suggested in these articles for addition to high grade ore is low, being about 0.01 weight %.
While current processes are satisfactory for their intended purpose, there is an ongoing need to improve process efficiency especially as it relates to oil sands of poor quality.

BRIEF SUMMARY

Disclosed herein compositions and processes for enhancing recovery of bitumen from oil sands ore. In one embodiment, the composition comprises at least one C₁-C₇monocarboxylic acid salt and/or acid in an aqueous liquid carrier; and oil sands ore containing bitumen, wherein the at least one C₁-C₇monocarboxylic acid salt and/or acid is in an amount effective to separate the oil sands into a froth phase, a middling phase, and sand and rock phase.
A process for enhancing the efficiency of bitumen recovery from oil sands ore comprises contacting the oil sands ore containing bitumen with an aqueous solution comprising at least one C₁-C₇monocarboxylate salt or acid.
In another embodiment, the process comprises mixing oil sands ore with a first aqueous solution to form a slurry; aerating the slurry to form a froth containing bitumen within the slurry; separating the froth from the slurry; adding a second aqueous solution comprising at least one C₁-C₇monocarboxylate salt and/or acid, wherein adding the second solution is prior to or during one or more of the preceding steps; and isolating bitumen from the froth.
The disclosure may be understood more readily by reference to the following detailed description of the various features of the disclosure and the examples included therein.

BRIEF DESCRIPTION OF THE DRAWINGS

Referring now to the figures wherein the like elements are numbered alike:

FIGS. 1-3 pictorially illustrate, after mixing, a separation flask of a control sample that contained toluene and aqueous bitumen foam, a sample containing 5% potassium formate by weight of the bitumen foam, and a sample containing 50% potassium formate by weight of the bitumen foam, respectively.

DETAILED DESCRIPTION

Disclosed herein are processes for separating trapped and bound bitumen from oil sands. The process generally includes adding at least one carboxylate salt and/or acid during a bitumen separation process and in an amount effective to lower interfacial surface tension. The process for separating the trapped and bound bitumen from oil sands is applicable to both surface mining and in situ mining techniques. In one embodiment, the carboxylate salt and/or acid is a C₁-C₇alkyl, and C₁-C₂alkyl in other embodiments. In another embodiment, the carboxylate salt and/or acid is a monocarboxylate salt and/or acid. Exemplary carboxylate salts include, without limitation, formates, acetates, and mixtures thereof. The cation is not intended to be limited and can be sodium, potassium, cesium, ammonium, and the like. Advantageously, the addition of the carboxylate salts and/or acids as defined above increases separation efficiency and reduces energy consumption by lowering viscosity of the separated oil, thus lowering pumping costs as well as increasing the pipeline capacity of the oil sands pipeline. In addition, the inventive composition can eliminate the use of caustics such as sodium hydroxide, which represents a significant commercial advantage.
The at least one carboxylate salt and/or acid can be added prior to and/or during the bitumen extraction process. In one embodiment, the at least one carboxylate salt and/or acid is added during the conditioning step of a hot water process for extracting bitumen. By way of example, the carboxylate salt and/or acid is added to an aqueous solution with hot water at a temperature within a range of about 40° C. to about 90° C. to condition the oil sand ore for quick release of the bitumen. Alternatively, the aqueous solution containing the carboxylate salt and/or acid can be vigorously mixed with the oil sands in the large tumblers or conditioning drums or an extraction pipeline without the addition of hot water. That is, the aqueous solution containing the carboxylate salt and/or acid can be added directly to the oil sand or to an oil sand water mixture, wherein the conditioning step can be free of a heating step, thereby providing significant energy savings. In still other embodiments, the process temperature of a slurry based extraction process is between about 0° C. and 60° C. to which the carboxylate salt and/or acid can be added.
It has been discovered that the aqueous solution containing the carboxylate salt and/or acid efficiently breaks the large lumps of the oil sands to form the slurry. Conditioning in this manner can be with or without the addition of an aqueous base such as sodium hydroxide. As is known in the art, sodium hydroxide is typically added to the froth to disperse the oil sands and reduces the viscosity of the slurry. However, the addition of sodium hydroxide adds expense to the process. Moreover, the middling phase is substantially non-transparent due to the significant amounts of sand and bitumen retained therein. Applicants have discovered that the addition of the carboxylate acid and/or salts of the present disclosure to the slurry (without caustic, e.g., sodium hydroxide) qualitatively resulted in a significantly lesser amount of sand remaining in the middling phase. The treated slurry with the carboxylate salt and/or acid (without the addition of sodium hydroxide) has been found to settle immediately upon resting to provide a substantially clear middling phase. In contrast to froth treatment with sodium hydroxide, the froth with the carboxylate salt and/or acid will settle to a greater degree than with caustic to form a sediment layer and supernatant water in a shorter period of time. Moreover, significantly less foam appears to have been formed.
The aqueous solution containing the at least one carboxylate salt and/or acid can have a concentration of 1 to 75 weight percent. In other embodiments, the aqueous solution containing the carboxylate salt and/or acid can have a concentration of 5 to 50 weight percent. Any source of water can be used to form the aqueous solution containing the carboxylate salt or acid. If used in conjunction with the hot water process, the carboxylate salt and/or acid can be added to the hot water as a solid in an amount effective to provide a concentration of 1 to 75 weight percent, and 5 to 50 weight percent in other embodiments.
Once extraction of bitumen has taken place, the aqueous solution containing the carboxylate salt or acid can be sent to the tailings pond. In surface mining the oil sands, the aqueous solution containing the carboxylate salt and/or acid can be recycled.
The composition may further include an additive such as a surfactant, an anti-foaming agent, a polymer, a flocculent, a mineral oil or a mixture thereof. In one embodiment, the additives are in an amount of 0.01 to 10 weight percent based on a total weight of the composition.
In order that the disclosure may be more readily understood, reference is made to the following examples, which are intended to illustrate the invention, but not limit the scope thereof.

Example 1

In this example, extraction of bitumen from bitumen foam was examined as a function of potassium formate concentration.
In a separation flask, three samples of toluene and aqueous bitumen foam with and without different concentrations of an aqueous potassium formate solution were vigorously mixed. A control sample contained no potassium formate was compared to samples containing 5% (wt/wt) potassium formate aqueous solution and at 50% (wt/wt) potassium formate aqueous solution. As shown in FIGS. 1-2, the samples containing the potassium formate solution visibly provided significantly improved phase separation when compared to the sample that did not include the carboxylate additive as shown in FIG. 3.
This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to make and use the invention. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.

Claims

1. A composition for enhancing the efficiency of bitumen recovery from oil sands ore, comprising:

at least one C₁-C₇monocarboxylic acid salt and/or acid in an aqueous liquid carrier; and

oil sands ore containing bitumen, wherein the at least one C₁-C₇monocarboxylic acid salt and/or acid is in an amount effective to separate the oil sands into a froth phase, a middling phase, and sand and rock phase.

2. The composition of claim 1, wherein the C₁-C₇monocarboxylic salt is potassium formate, sodium formate, cesium formate, ammonium formate, or a mixture thereof.

3. The composition of claim 1, wherein the C₁-C₇monocarboxylic salt and/or acid is in an amount of 1 to 75 weight percent based on a total weight of the composition.

4. The composition of claim 1, wherein the C₁-C₇monocarboxylic salt and/or acid is in an amount of 5 to 50 weight percent based on a total weight of the composition.

5. The composition of claim 1, further comprising an additive in an amount of 0.01 to 10 weight percent based on a total weight of the composition, wherein the additive is a surfactant, an anti-foaming agent, a polymer, a flocculant, a mineral oil or a mixture thereof.

6. A process for enhancing the efficiency of bitumen recovery from oil sands ore, comprising:

contacting the oil sands ore containing bitumen with an aqueous solution comprising at least one C₁-C₇monocarboxylate salt and/or acid.

7. The process of claim 6, wherein contacting the oil sand ore with the aqueous solution is at a temperature of 0° C. to 60° C.

8. The process of claim 6, wherein the C₁-C₇monocarboxylic salt is potassium formate, sodium formate, cesium formate, ammonium formate, or a mixture

9. The process of claim 6, further comprising adding an additive to the aqueous solution in an amount of 0.01 to 10 weight percent based on a total weight of the solution, wherein the additive is a surfactant, an anti-foaming agent, a polymer, a flocculant, a mineral oil, or a mixture thereof.

10. The process of claim 6, wherein the oil sand is surface mined and the process further comprises recycling the aqueous solution.

11. The process of claim 6, wherein the process is free of a heating step.

12. The process of claim 6, wherein the oil sands ore containing the bitumen is a froth.

13. The process of claim 6, wherein the at least one C₁-C₇monocarboxylic salt and/or acid is in an amount of 1 to 75 weight percent based on a total weight of the aqueous solution.

14. A process for extracting bitumen from an oil sand, comprising:

mixing oil sands ore with a first aqueous solution to form a slurry;

aerating the slurry to form a froth containing bitumen within the slurry;

separating the froth from the slurry;

adding a second aqueous solution comprising at least one C₁-C₇monocarboxylate salt and/or acid, wherein adding the second solution is prior to or during one or more of the preceding steps; and

isolating bitumen from the froth.

15. The process of claim 14, wherein the C₁-C₇monocarboxylic salt is potassium formate, sodium formate, cesium formate, ammonium formate, or a mixture thereof.

16. The process of claim 14, wherein the C₁-C₇monocarboxylic salt and/or acid is in an amount of 1 to 70 weight percent based on a total weight of the composition.

17. The process of claim 14, wherein isolating the bitumen comprises heating the froth in an amount effective to substantially deaerate the froth; and adding naptha to the deaerated froth.

18. The process of claim 14, wherein the first aqueous solution comprises hot water at a temperature of about 40° C. to about 90° C.

19. The process of claim 14, wherein the first aqueous solution comprises hot water at a temperature of about 0° C. to about 60° C.