CA2755518A1 - Treatment of oil sand bitumen to produce low calcium bitumen - Google Patents

Abstract

A method is provided to prepare a low calcium bitumen composition from an oil sand composition, the method including the steps of: contacting an oil sand composition with water and a basic material such as, for example, caustic to form a water and oil sand slurry; separating the water and oil sand slurry into a froth, comprising water, some mineral solids, and a bitumen composition, and a underflow stream comprising the majority of the mineral solids present in the oil sand composition and a majority of the water present in the water and oil sand slurry; contacting at least a portion of the bitumen composition with an acid; and separating the acid from the bitumen wherein at last a portion of calcium present in the bitumen composition has partitioned to the acid.

Description

TREATMENT OF OIL SAND BITUMEN TO PRODUCE LOW CALCIUM
BITUMEN
Field of the Invention The invention relates to a method and apparatus for treatment of oil sand bitumen to produce a bitumen product having a low concentration of calcium.

Background Oil sand is essentially a matrix of bitumen, mineral material and water, and possibly encapsulated air. The bitumen component of oil sand consists of viscous hydrocarbons which behave much like a solid at normal in situ temperatures and which act as a binder for the other components of the oil sand matrix. Oil sand will typically contain about 10%
to 12% bitumen and about 3% to 6% water, with the remainder of the oil sand being made up of mineral matter. The mineral matter component in oil sand may contain about 14% to 20% fines, measured by weight of total mineral matter contained in the deposit, but the amount of fines may increase to about 30% or more for poorer quality deposits. Oil sand extracted from the Athabasca area near Fort McMurray, Alberta, Canada, averages about 11 % bitumen, 5% water and 84% mineral matter, with about 15%
to 20% of the mineral matter being made up of fines. Oil sand deposits are mined for the purpose of extracting bitumen from them, which is then upgraded to synthetic crude oil.

A widely used process for extracting bitumen from oil sand is the "water process". In this process, aggressive thermal action and aggressive mechanical action are used to liberate and separate bitumen from the oil sand. An example of the water process is the hot water process. In the hot water process, oil sand is first conditioned by mixing it with water at about 95°
Celsius and steam in a conditioning vessel which vigorously agitates the resulting slurry in order to disintegrate the oil sand. Once the disintegration of the oil sand is complete, the slurry is separated by allowing the sand and rock to settle out. Bitumen, with air entrained in the bitumen, floats to the top of the slurry and is withdrawn as a bitumen froth. The remainder of the slurry is then treated further or scavenged by froth flotation techniques to recover bitumen that did not float to the top of the slurry during the separation step. The froth is further treated to separate solids and water from liquid hydrocarbons. Such a process is suggested in US patent nos. 5,645,714, and 4,533,459 the disclosures of which is incorporated herein by reference.

Canadian patent number 2,232,929, the disclosure of which is incorporated herein by reference, discloses an improvement to the hot water process that utilizes a paraffinic solvent to extract bitumen from the bitumen froth.

US patent no. 6,905,593 suggests a method to remove calcium from conventional crude oil by extraction utilizing an aqueous mixture of and acetate ion and an alkaline material having a pH
in the range of 3.0 to 5Ø Calcium removal from crude oils was found to be particularly effective within this range of pH.

Summary of the Invention A method is provided to prepare a low calcium bitumen composition from an oil sand composition, the method comprising the steps of: contacting an oil sand composition with water and a baseic material to form a water and oil sand slurry; separating the water and oil sand slurry into a froth, comprising water, some mineral solids, and a bitumen composition, and a underflow stream comprising the majority of the mineral solids present in the oil sand composition and a majority of the water present in the water and oil sand slurry; contacting at least a portion of the bitumen composition with an acid; and separating the acid from the bitumen wherein at last a portion of calcium present in the bitumen composition has partitioned to the acid.

The present invention is particularly applicable for removal of at least a portion of calcium from an oil sand bitumen wherein the oil sand bitumen has been treated with caustic (or some other base, for example, sodium carbonate or sodium silicate), as a part of a hot water treatment system.
Use of caustic in this process can enhance this extraction of bitumen from oil sands, but contact with caustic has been found to increase retention of calcium in the bitumen.
Retention of calcium in bitumen may be detrimental to performance of some bitumen upgraders. Presence of more than 5 parts per million by weight of calcium in bitumen can be detrimental to upgraders that utilize contact with hydrogen and catalyst, typically at elevated temperatures and pressures.

In one embodiment of the present invention, the hydrocarbon mixture of the froth is contacted with acetic acid prior to the froth being separated into a bitumen product, a stream of mineral solids and water and optionally a stream of asphaltenes. Addition of acetic acid according to this embodiment may be directly to a froth that is then treated according to a paraffinic solvent treatment process to separate a bitumen product from the froth. The paraffinic solvent process may be a process such as that disclosed in Canadian patent number 2,232,929.

In another embodiment of the present invention, a hydrocarbon solvent may be used according to the process disclosed in 2,232,929, and an aqueous acidic solution may be contacted with the solvent-diluted bitumen prior to solvent being recovered from the solvent for recycling. At this point in the process, the density of the phase containing the bitumen differs from the density of the aqueous acidic solution significantly and the majority of mineral solids are removed, enabling easy separation of the two phases.

2 Brief description of the Figure The Figure is a process flow drawing for the process of the present invention.
Detailed Description of the Invention Referring now to the Figure, an oil sand ore stream, 101, is contacted with water 102, and caustic, or another basic material, 103, in, for example, a mixer 140, to form a water and oil sand slurry 104. Sufficient caustic may be included so that the pH of the aqueous phase of the water and oil sand slurry is above about 8. The oil sand ore can be a mined bitumen ore from a formation such as oil sands found in the Athabasca area near Fort McMurray, Alberta, Canada. The ratio of oil sand ore to water may be, for example, in the range of I to 6 or alternatively in the range of I to 2. The oil sands may contain between 75 and 95 percent by weight of mineral solids, and may contain between 10 and 20 percent by weight hydrocarbons. The hydrocarbon portion of the oil sands may have a gravity of between 7 and 10 API and may contain from 10 to 25 percent by weight of asphaltenes. Other components of the hydrocarbon portion of the oil sand ore may be 10 to 40 percent by weight aliphatics, 5 to 20 percent by weight aromatics, and 10 to 50 percent by weight polar compounds. The mixer may agitate the slurry to break up solids and to increase the area of contact between the solids and the water. The mixer may also heat the slurry to a temperature of, for example, between 35 C and 90 C to enhance extraction of hydrocarbons from the solids. Air and chemicals such as surfactants maybe added to the slurry to further enhance separation of the hydrocarbons from the solids. Alternatively, liberation of hydrocarbon from mineral material may be accomplished in a slurry conditioning transportation line.

The water and oil sand slurry 104 optionally may be screened in a screener 141 to remove larger solids 106 from a remaining slurry stream 105. Caustic, or another basic material, 103, could optionally be added to slurry stream 105, or to the water and oil sand slurry 104, either in addition to, or instead of being added to the mixer 140, Slurry stream 105 may be further processed to provide an initial solids separation in a first separator 142 producing a first underflow stream 107, containing solids and water with some bitumen, and a froth stream 108. The forth stream contains a majority of the bitumen from the oil sands stream, along with entrained water and solids. The bitumen contained in the froth may be a bitumen composition having a content of calcium between, for example, 5 and 300 parts per million by weight. Typically, the froth stream contains about 60 weight percent bitumen, about 30 weight percent water, and about 10 weight percent mineral solids. The first separator may include additional steps and equipment, such as, for example, flotation cells, to increase the bitumen recovery and de-aerators to remove excessive air. Because of the pH of the aqueous phase of the

3 oil sand slurry is above 8, certain ions such as calcium ions, tend to remain in the hydrocarbon phase in complexes with, for example, naphthenates. The concentration of calcium present in the hydrocarbon phase mixture may be, for example, between 5 and 200 parts per million by weight.
Processing of the oil sand ore stream to extract hydrocarbons as a froth may include additional steps and equipment known as the hot water process, such as the process suggested in US patent 4,533,459.

Froth, 108, from the first separator may be mixed with solvent 109, and, in one embodiment of the present invention, acetic acid 110, in a solvent-froth mixer 143. Alternatively, acid 110 may be added before mixer 143 and after separator 142. Alternatively, acid 110 may be added after mixer 143. The solvent may be a hydrocarbon solvent. The hydrocarbon solvent may be a paraffinic solvent. The paraffinic solvent tends to reject ashphaltenes into tailings, resulting in a higher quality hydrocarbon product from the subsequent physical separation.
The solvent could, in another embodiment be a naphtha solvent, in which case asphaltenes may not be rejected into the tailings.

The paraffinic solvent process such as the process disclosed in Canadian patent no.
2,232,929 is capable of providing a bitumen product that is very low in content of entrained water and solids. Because entrained water and solids also contain calcium ions, and the acidic extraction process may not effectively remove calcium from such entrained water and solids, the paraffinic solvent process is a preferred process to separate froth into the bitumen product and the separate streams of solids, water, and optionally asphaltenes, but other processes could be utilized that are effective to separate the froth into a product bitumen that is low in solids and water content. For example, the naphtha solvent treatment process, optionally with additional steps to remove a sufficient amount of entrained solids and/or water.

The acid may be added in an amount of moles between about one and ten times the molar amount of calcium present in the hydrocarbon phase of the oil sand composition. The pH of the aqueous phase of the froth, after addition of acid, may be, for example, lower than 8, or lower than 7.

The solvent froth mixer product, 111, is separated into a solvent diluted bitumen 112 and tailings 113, in a hydrocarbon enrichment separator 144.

The solvent diluted bitumen stream 112 may be, in some embodiments, combined with an acid 118. The acid may comprise mineral acids, organic acids or carboxylic acids. The amount of acid may be, for example, in the range of 2 to 200 percent by volume of the amount of solvent diluted bitumen. In an embodiment were the solvent diluted bitumen is contacted with an acidic

4 aqueous stream, the combined stream may be mixed, for example, by an in-line mixer, or by a pump, or by a mixing valve, and then separated by known means to separate liquid phases, such as hydrocyclones, settling vessels, or plate separators. A portion of the acidic components may be, after contact with the bitumen, salts of the acids, for example, calcium salts.

Demulsifer(s) and/or electric field can be employed to enhance separation of solvent-diluted bitumen and aqueous phase in Separator 145. Separator 145 makes this separation of the combined acidic aqueous stream and solvent diluted bitumen stream 114 which, in an embodiment where either the froth or the solvent diluted bitumen is contacted with an acid, reduced in calcium content. Separator 145 separates the combined acid and solvent diluted bitumen stream into a reduced calcium solvent diluted bitumen 114 and an acid aqueous phase 115, which could optionally be recycled. Some make-up acid would be required to the recycled acidic aqueous stream, with a corresponding blow down of spent acid to remove calcium from the system. In one embodiment, the acid 110 used to contact froth 108 and the acid 118 used to contact solvent-diluted bitumen 112 are different acids, where, for example, acid 110 may be an acetic acid solution and acid 118 may be an hydrochloric acid solution. To produce low calcium bitumen product, acid employment may not be needed at both locations (110 and 118) simultaneously.

Hydrocarbon enrichment separator 144 may comprise, for example, two or three stages of counter current contacting of underflow from the separators with solvent such as taught in Canadian patent number 2,232,929.

Solvent diluted bitumen 114, or in the embodiment where acid is contacted with the solvent diluted bitumen and then separated, reduced calcium solvent diluted bitumen 114, may be routed to a solvent recovery unit 147. The solvent recovery unit may be any known means for removing more volatile hydrocarbons from less volatile hydrocarbons, for example, distillation. The solvent recovery unit 147 produces a recycle solvent stream 119 and a bitumen product stream 120.

Tailings 113 from the hydrocarbon enrichment separator 144 are then separated into a second recycled solvent stream 116 and a tailings solvent recovery unit underflow stream 117 in a tailings solvent recovery unit 146.

The second recycled solvent stream 116, may be combined with the recycled solvent stream 119 and additional make-up 121 go become the solvent stream 109.

Bitumen product stream 120 may then be further processed in a hydrogen addition upgrader 148 by contact with hydrogen 122 at elevated temperatures and pressures to produce upgraded products 123. The process capable of upgrading the bitumen product may be, for example, one using any conventional reaction apparatus. Examples of typical reaction apparatus

5 include, but are not limited to, a tubular reactor, a tower reactor and a soaker reactor.
Although the hydrogen addition upgrader process may be conducted in a batchwise manner, it may also be conducted in a continuous manner. Accordingly, the bitumen and a hydrogen-containing gas are continuously supplied to the reaction zone in a reaction apparatus to conduct a partial hydroconversion and concurrent demetallization of the bitumen while continuously collecting the reduced calcium bitumen feedstock.
The reduced calcium bitumen feedstock may then be conveniently directly introduced into an ebullated bed reactor system. The ebullated bed reactor systems are well known in the art, and generally comprise introducing a hydrogen-containing gas and heavy hydrocarbon feedstock into the lower end of a generally vertical catalyst containing reaction vessel wherein the catalyst is placed in random motion within the fluid hydrocarbon whereby the catalyst bed is expanded to a volume greater than its static volume. Such processes are described in the literature, e.g. U.S. Pat.
Nos. 4,913,800, 32,265, 4,411,768 and 4,941,964, the disclosures of which are incorporated herein by reference. Suitable processes are commercially known as the H-Oil Process (Texaco Development Corp.) and LC-Fining Process (ABB Lummus Crest, Inc.).

Typically, catalyst employed in the ebullated bed are the oxides or sulfides of a Group VIB
metal of a Group VIII metal. These include, for example, catalysts such as cobalt-molybdate, nickel-molybdate, cobalt-nickel-molybdate, tungsten-nickel sulfide, tungsten sulfide, mixtures thereof and the like, with such catalysts generally being supported on a suitable support such as alumina or silica-alumina.
In general, the reaction conditions in the ebullated reactor system comprise temperatures in the order of from about 343.degree to 482°C, preferably from about 400 to about 454.degree C. operating pressure of from about 3550kPa (500 psig) to about 27700 kPa (4000 psig), and hydrogen partial pressures generally being ranging from about 3450 to 20700 kPa (500 to 3000 psia).

The hydrogen addition upgrader may also have other processes associated with it. Such as the reduced calcium bitumen may first be processed in a atmospheric and/or vacuum distillation unit to remove the lighter portions of the reduced calcium bitumen, with the residual from the distillation process going to the hydrogen addition upgrader.

The invention also includes the apparatus capable of performing the method.
Examples Froth from a commercial oil sands facility using a water process for initial separation of mineral components from bitumen was heated for about one hour in an oven at 77 C. The froth

6 was then homogenized for 12 minutes using a hand-held drill and paint mixer assembly. Once homogenized, the froth was sampled into a metal mixing vessel. The vessel was then placed into a temperature controlled (25 C) water bath. A paraffinic hydrocarbon solvent containing hydrocarbons having 5 and 6 carbons was weighed into a separate sealed container and placed in the same temperature controlled (25 C) water bath. Once froth and solvent were at temperature, if required, an acid was added to the froth. After acid was added, solvent was added. The contents were mixed for 10 minutes at 500 RPM. After mixing, the metal vessel contents were transferred into a 1000 mL graduated cylinder and the cylinder placed into the temperature controlled (25 C) water bath. The interface level of the settling water/solids/asphaltenes aggregates was recorded with respect to time. After settling, the hydrocarbon phase was sampled for solvent-to-bitumen ratio (SB) determination and calcium analysis. The heavy phase was also collected and centrifuged at 2000 rpm for ten minutes. After centrifugation, the underflow separates into the three phases of hydrocarbon, water and solids. The water phase was collected and its pH
determined.

Testing was done using three types of such froth. These froths were: 1) high calcium froth (about 100 ppm calcium, bitumen basis), 2) mid calcium (about 16 ppm calcium) and 3) second high calcium forth (about 120 ppm calcium).

Chemical aids were typically added to froth in the form of stock solutions which contained about 5 to 20 % acid by mass. The effect of the concentration of the acid stock solution was tested on a limited number of acids and was not found to have any significant effect.
A series of screening tests were performed in order to find acids that are effective at removing organically bound calcium. These tests typically used mid calcium froth (about 16 ppm calcium, bitumen basis). The results of these screening tests are shown in table 1.

Reduction in Ca pH of water concentration with Settling Rate (% of Chemical Added phase acid addition (%,) Standard) H2SO4 7.2 95 55 HCl 4.5 100 30 Acetic Acid 6.8 98 85

7 EDTA 7.3 25 90 Oxalic Acid 7.0 - 40 90 Citric Acid 4.0 10 100 NaHCO3 7.2 - 20 100 H3PO4 5.2 50 100 From Table I it can be seen that acetic acid H2SO4 as well as HCl addition were found to produce diluted bitumen with very low Ca concentrations.

From these screening tests H2SO4, HCI, and acetic acid were found to be effective at removing calcium from bitumen, the other chemicals tested were not considered effective.

Further testing was conducted with H2SO4, HCI and acetic acid addition to high calcium froth (about 120 ppm by weight calcium).

Settling rate as a function of pH after acid addition are shown in Figure 2.
For control tests, no chemicals were added. Acid added for each test is indicated in the figure.
Acetic acid was added to froth as a 20 % (by mass) solution, except for the circled data points for which glacial (-100 %m) acetic acid was used.

While these acids had an identical pH- calcium in bitumen relation, the effect of the pH on the settling rate was found to depend on the type of acid added, as shown in figure 2. A 15 to 20 %
reduction in the settling rate was found when acetic acid was added, while when strong mineral acids (H2SO4 or HCI) were added, the settling rate decreased 50 to 80 %, depending on the final pH.

In another two examples, acetic acid and hydrochloric acid were added, respectively, to a composition of high calcium bitumen and paraffinic solvent such as stream 112 of the Figure, and agitated. The composition was then separated into a hydrocarbon phase and an aqueous phase by gravity separation and calcium content of the hydrocarbon phase was determined. In this example, the aqueous phase separated readily from the hydrocarbon phase, and low calcium hydrocarbon was produced.

In another two examples, acetic acid and hydrochloric acid were added, respectively, to a composition of high calcium bitumen such as stream 120 of the Figure, and agitated. The

8 composition was then separated into a hydrocarbon phase and an aqueous phase by gravity separation and calcium content of the hydrocarbon phase was determined. In these examples, low calcium hydrocarbon was produced. The aqueous phase separated acceptably, but not as quickly as the examples wherein the acidic compositions were added to the solvent diluted bitumen.

9

Claims (12)

1. A method to prepare a low calcium bitumen composition from an oil sand composition, the method comprising the steps of:

contacting an oil sand composition with water and a basic material to form a water and oil sand slurry;

separating the water and oil sand slurry into a froth, comprising water, some mineral solids,and a bitumen composition, and a underflow stream comprising the majority of the mineral solids present in the oil sand composition and a majority of the water present in the water and oil sand slurry;

contacting at least a portion of the bitumen composition with an acid; and separating the acid from the bitumen wherein at last a portion of calcium present in the bitumen composition has partitioned to the acid.

2. The method of claim 1 further comprising the step of separating the froth into a bitumen composition and a water stream.

3. The method of claim 2 wherein the step of separating the froth into a bitumen composition and a water stream comprises mixing the froth with a hydrocarbon solvent and then separating the froth and hydrocarbon mixture into a solvent diluted bitumen and water stream.

4. The method of claim 3 wherein the hydrocarbon solvent is a paraffinic hydrocarbon solvent.

5. The method of claim 3 wherein the acid is combined with the froth before the froth and hydrocarbon mixture is separated into a solvent diluted bitumen and water stream.

6. The method of claim 5wherein the acid comprises aqueous acetic acid.

7. The method of claim 3 wherein the acid is combined with the solvent diluted bitumen.

8. The method of claim 7 wherein the acid is a mineral acid.

9. The method of claim 3 further comprising separating at least a portion of the hydrocarbon solvent from the solvent diluted bitumen to produce a recyclable solvent and a bitumen product.

10. The method of claim 9 wherein the acidic composition is contacted with the bitumen product.

11. The method of claim 4 wherein the hydrocarbon solvent is a paraffinic solvent comprising paraffins having between 4 and 8 carbons.

12. The method of claim 1 further comprising the step of hydrocracking the bitumen product in an ebullated bed catalytic hydrocracking system.