METHOD FOR DESTABILIZING BITUMEN-WATER AND OIL-WATER EMULSIONS USING LIME

- Apex Engineering Inc.

In a process for destabilizing bitumen-water emulsions to facilitate bitumen recovery therefrom, bitumen-water interfacial tension is increased by reducing or eliminating the activity of functional groups acting as surfactants by treating the emulsions with one or more additives of ionic base to increase the hydrophobic characteristics of bitumen droplets in the emulsions and thus increase their attraction to each other and to gas bubbles. Additives effective for this purpose include salts of the Periodic Table's Group II earth alkali metals cations such as magnesium, calcium, strontium, and barium, and Group III metals cations such as aluminum. Mechanical agitation or injection of a gas stream into the destabilized bitumen-eater emulsion may be used to form bitumen-rich froth. The additives used for destabilization of the emulsions also promote flocculation of clay-size particles in the froth and improve the chemistry of the recovered water.

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Description
FIELD OF THE DISCLOSURE

The present disclosure relates to methods and processes for destabilization of bitumen-water and heavy-oil-water emulsions and froths, such as emulsions and froths produced by processes for extraction of bitumen and heavy oil.

BACKGROUND

As used in this patent specification, the term “bitumen” is intended to denote a solid or semi-solid form of petroleum, as distinct from a readily flowable hydrocarbon substance such as conventional liquid crude oil. The term “heavy oil” is used herein to denote a highly viscous form of crude oil that, although liquid in a strict sense, cannot readily flow to production wells under normal reservoir conditions due to its inherent viscosity. “Bitumen” (which alternatively may be referred to as “extra heavy oil”) typically has in the range of about 7 to 12° API gravity (API gravity being a measure of crude oil quality based on the density) and greater than 15% asphaltenes by mass. “Heavy oil” typically has in the range of about 17 to 22° API gravity and about 10% asphaltenes. The term “light oil” generally refers to crude oil having about 25° API gravity or greater and about 1.5% asphaltenes. The general term “oil” in the present disclosure may refer to bitumen, heavy oil, and/or light oil, depending on the context.

As conventional oil resources are being depleted, the world's liquid hydrocarbon demand is increasingly supplied by bitumen and heavy oil. Total bitumen contained in the Athabasca oil sands deposits in northern Alberta, Canada is estimated at about 1.7×1012 barrels, which is ranked as the world's second largest hydrocarbon resource; only about 10% of these deposits are suitable for surface mining while the remaining 90% is suitable for thermal in-situ processes such as SAGD and CSS processes. Bitumen-water emulsions are produced by using both oil-sands-ore-water-slurry-based bitumen extraction and steam-assisted bitumen recovery processes. As a result, destabilization of bitumen-water and heavy-oil-water emulsions is an important process for the industry.

In the steam assisted in-situ recovery processes, bitumen-water or oil-water emulsions are produced in the pores of the reservoir, or during the pumping of bitumen-water (condensed steam) and oil-water mixtures from reservoir to the surface facilities. Regardless of the causes of the formation of these emulsions, upon the recovery of these emulsions in the surface facilities emulsion breaking additives such as light hydrocarbons, synthetic crude oil or emulsion destabilizing specialty chemicals are added at different proportions for the destabilization of the emulsion structure. Special vessels, mostly operating as flotation cells, are used for the recovery of bitumen or heavy oil and water as two separate fluids streams.

Bitumen and heavy oil are commonly produced using steam-assisted thermal in-situ recovery processes, such as steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) processes. In these processes, bitumen and heavy oil are recovered in the form of bitumen-water or heavy-oil-water emulsions. As used in this patent specification, the term “oil-water emulsion” is to be understood as referring to an emulsion containing heavy oil, unless otherwise indicated.

Bitumen-water emulsions are also produced during the utilization of surface mineable oil sands ore, where bitumen-water emulsions are produced by the oil-sands-ore-water-slurry-based extraction processes. Oil-water emulsions are also produced by enhanced oil recovery methods such as water flooding processes.

BRIEF SUMMARY

The present disclosure teaches methods and processes for destabilization of bitumen-water and oil-water emulsions by treating such emulsions with lime (as calcium oxide—CaO). In alternative embodiments of methods and processes in accordance with the present disclosure, the emulsions may be treated with the Periodic Table's Group II earth alkali metals cations such as magnesium (Mg2+), calcium (Ca2+), strontium (Sr2+), and barium (Ba2+) as destabilizing additives for the separation and recovery of bitumen and water (or heavy oil and water) as separate streams. In other embodiments, the Periodic Table's Group III metals cations such as aluminum (Al3+) may be used as destabilizing additives, with such cations being most effective as additives to acidic emulsions (i.e., having a pH less than 7.0).

Processes in accordance with the present disclosure also promote flocculation of the clay particles and precipitates naphthenic acids salts, by which they are separated from the emulsion fluids; and, improves chemistry of the recovered water for its recycling to the extraction plant or for its use for any purpose. The present disclosure has applications in oil production and clean-up of contaminated soils with hydrocarbons and/or organic substances.

The present disclosure teaches methods and processes for destabilizing emulsions having constituents including water, hydrocarbons (or other organic substances), and solids, to facilitate separation of these constituents. Examples of emulsions that may be treated using methods and processes in accordance with the present disclosure include (but are not limited to):

    • (i) bitumen-water emulsions produced by ore-water-slurry-based processes for extraction of bitumen from surface-mined oil sands ore;
    • (ii) bitumen-water emulsions produced by in-situ bitumen extraction processes including SAGD and CSS processes;
    • (iii) bitumen-water emulsions in the form of froth produced by ore-water-slurry-based bitumen extraction processes;
    • (iv) oil-water emulsions produced by water flooding or other enhanced oil recovery processes; and
    • (v) oil-water-solids emulsions and or suspensions for the clean-up of contaminated soils with hydrocarbons and/or other organic substances.

Bitumen-water and heavy-oil-water emulsions produced by SAGD, CSS, or water flooding processes typically contains about 15% to 30% bitumen or heavy oil, and a small amount (typically about or less than 1%) of inorganic solids. The major fraction of the solids is typically composed of silt and clay particles, which are also called fines, which term is commonly used to denote particles passing a 320 mesh (i.e., 45 micron) screen. Bitumen and solids contents of the froth produced by ore-water-slurry-based extraction processes are generally higher; a typical composition of such froth is about 60% bitumen, 30% water, and 10% solids (with the major fraction of the froth solids consisting of silt and clay particles). Solids accumulate at the bitumen-water interface and have to be flocculated and separated from the bitumen or heavy oil. The solids contained in these emulsions have to be considered in the design of bitumen-water-emulsion-destabilizing processes; they have to be flocculated and separated from the emulsion.

The present disclosure teaches methods for:

    • (i) destabilization of emulsions to separate the constituent solids, bitumen (or heavy oil), and water to facilitate recovery of the bitumen (or heavy oil) and water as separate streams;
    • (ii) flocculation of silt and clay particles and their precipitation and separation from the emulsion fluids;
    • (iii) improvement of the chemistry of the recovered water (alternatively referred to as “release water”) for recycling to bitumen or heavy oil recovery processes; and
    • (iv) destabilization of hydrocarbon-water-solids emulsions and/or suspensions to facilitate clean-up of soils contaminated with hydrocarbons and/or other organic substances.

Bitumen contained in Athabasca oil sands deposits in Alberta, Canada is estimated at about 1.7×1012 barrels, which is ranked as the world's second largest hydrocarbon resources. Only about 10% of these deposits are suitable for surface mining, while the remaining 90% is suitable for thermal in-situ recovery processes such as SAGD and CSS. Bitumen-water emulsions are produced by using both ore-water-slurry-based bitumen extraction and steam-assisted bitumen recovery processes. As a result, destabilization of bitumen-water and heavy-oil-water emulsions is an important process for the industry.

In steam-assisted in-situ recovery processes, bitumen-water or oil-water emulsions are produced in the pores of the subsurface reservoir, or during the pumping of bitumen-water (condensed steam) and oil-water mixtures from the reservoir to the surface facilities. Regardless of the causes of the formation of these emulsions, upon the recovery of these emulsions in the surface facilities, emulsion-breaking additives such as light hydrocarbons, synthetic crude oil, and/or emulsion-destabilizing specialty chemicals are added to destabilize the emulsion structure. Special process vessels, most typically operating as flotation cells, are used for the recovery of bitumen (or heavy oil) and water as separate fluid streams.

High alkalinity of the water in the reservoir (which could be connate water and/or water formed by condensed steam) increases the solubility of naturally-occurring naphthenic and asphaltic acids in bitumen or heavy oil which act as surfactants and reduce bitumen-water or oil-water interfacial tension. Reduction in bitumen-water or oil-water interfacial tension is a primary mechanism in the formation of bitumen-water or oil-water emulsions. Low bitumen-water or oil-water interfacial tension increases the attraction of bitumen or oil droplets to water, reducing the probability of coalescence of bitumen or oil droplets when the emulsions are treated by mixing or flotation processes for purposes of separating the bitumen or oil from water.

Methods and processes as disclosed herein increase bitumen-water or oil-water interfacial tension by reducing or eliminating surfactant species with Ca2+ introduced by CaO addition into the emulsions. Therefore, the disclosed methods and processes increase the hydrophobic characteristics of bitumen and oil droplets in emulsions and make them more attractive to each other and to gas bubbles (e.g., air, flue gas) since most of the gas bubbles are also hydrophobic. The attraction of bitumen (and oil) droplets to gas bubbles makes facilitates more effective recovery of bitumen (or oil) by flotation-type processes that form bitumen-rich (or oil-rich) froth-type products.

The present disclosure is directed to methods and processes for increasing the bitumen-water or oil-water interfacial tension in bitumen-water or oil-water emulsions, thereby promoting breakdown of the emulsion structure and resultant destabilization of the emulsions, and facilitating separation and recovery of bitumen and water (or oil and water) different products. Methods and processes in accordance with the present disclosure also promote flocculation of silt and clay-size particles by reducing the activities of surfactant species and thereby reducing the wettability of these particles with water and promoting flocculation of the particles. In addition, methods and processes in accordance with the present disclosure improve the chemistry of the recovered water and reduce water-soluble naphthenic and asphaltic acids, thus making the recovered water more suitable for recycle to bitumen (or heavy oil) recovery plants.

Because the methods and processes disclosed herein increase the hydrophobic characteristics of bitumen and oil droplets in emulsions and make them more attractive to each other and to gas bubbles (e.g., air, flue gas), the performance of these methods and processes may be enhanced by injecting a gaseous substance (such as but not limited to air, combustion flue gas, steam, nitrogen (N2) or carbon dioxide (CO2)) injected into the separation vessel. Injection of a gaseous substance, as practiced in flotation processes, speeds up the emulsion destabilization and facilitates recovery of the bitumen in the form of bitumen-water-gas froth. This froth typically contains a small amount of solids, such as clay-size particles, depending on the process operating conditions. Turbulence created in the vessel by injection of gaseous substance promotes the rate of flocculation of clay-size particles.

The efficiency of the disclosed methods and processes typically will increase as the process temperature and pressure are increased. As an example, if such methods and processes are implemented for destabilization of bitumen-water or heavy-oil-water emulsions produced by SAGD or CSS processes, they will provide much better results if the bitumen-water or heavy-oil-water emulsions are processed at the production wellhead temperature and pressure operating conditions.

DESCRIPTION

There are two primary causes for the formation of bitumen-water or heavy-oil-water emulsions are formed in steam-assisted thermal recovery processes:

    • (i) interfacial tension in bitumen-water or heavy-oil-water mixtures is reduced by the activation of naphthenic acids naturally present in bitumen and heavy oil by alkaline water (condensed str\eam) in the reservoir having a pH greater than 7.0 (pH>7); and
    • (ii) exposure of bitumen-water or heavy-oil-water mixtures to mixing by any means, either in the reservoir or in the process of lifting of bitumen-water or heavy-oil-water mixture to the surface.

The pH is a measure of acidity of the aqueous systems which is defined as pH=−log[H+]; i.e., pH is defined as the negative of the logarithm of the molar proton concentration [H+]. By this definition, pH=7 for the neutral aqueous systems; acidity increases as pH is reduced from 7 to 0 (0<pH<7) and alkalinity increases as pH is increased from 7 to 14 (7<pH<14).

In the presently-disclosed methods and processes, bitumen-water or heavy-oil-water interfacial tension is increased by eliminating the activities of the functional groups acting as surfactants by treating the emulsions with one or more additives of ionic base. These additives reduce the activity of the functional groups acting as surfactants, thereby increasing bitumen-water or oil-water interfacial tension and destabilizing the emulsions. Since the emulsions' stability is reduced, they become structurally unstable. Any mechanical agitation or injection of a gas stream into destabilized emulsion results in the formation of bitumen-rich (or oil-rich) froth at the top of the process vessel. The chemical additives used for the destabilization of the emulsions also promote flocculation of clay-size particles in the froth and improve the chemistry of the recovered water.

Cost-effective and substantially environmentally-benign chemicals suitable for use as additives for purposes of the disclosed methods and processes include the salts of the Periodic Tables' Group II earth alkali metals cations such as magnesium (Mg2+), calcium (Ca2+), strontium (St2+), and barium (Ba2+) and the Periodic Tables Group III metals cations such as aluminum (Al3+). Salts of the Periodic Table's transient elements such as iron (Fe2+ and Fe3+) and zinc (Zn2+) could also be effective subject to any case-specific environmental considerations.

During or after treatment of bitumen-water or heavy-oil-water emulsions with such salts to destabilize the emulsion structure, the injection of air or any unreactive gas such as but not limited to nitrogen (N2), carbon dioxide (CO2), or flue gas composed primarily of N2, CO2, and unreacted oxygen (O2) produced from steam generating boilers, will promote separation of the water and bitumen phases of the emulsions. Injection of an unreactive gas into the emulsions promotes separation of bitumen or heavy oil from water, coalesces smaller bitumen or heavy oil droplets into larger droplets, and promotes the formation of bitumen-rich or heavy-oil-rich froth, which are important processes for efficient separation of bitumen or heavy oil from water. As used in this patent specification, the term “unreactive gas” refers to a gas that in non-combustible under process conditions.

Although several chemicals have been identified herein as being effective as additives for purposes of methods and processes in accordance with the present disclosure, calcium oxide (CaO, also known as lime) has been found to be particularly effective and advantageous for destabilization of bitumen-water or heavy-oil-water emulsions. CaO is a cost-effective chemical and is extensively used in the chemical industry. CaO is produced by thermal decomposition of calcite (CaCO3) by chemical reaction:


CaCO3→←CaO+CO2   (Equation 1)

When bitumen-water or oil-water emulsions are treated with CaO, CaO becomes calcium hydroxide (Ca(OH)2) in aqueous environments by the following reaction:


CaO+H2O→←Ca(OH)2   (Equation 2)

Also in aqueous environments, Ca(OH)2 dissociates to Ca2+ and OH− ions by the following reaction:


Ca(OH)2→←Ca2++2OH−  (Equation 3)

where the extent of the reaction favors towards Ca(OH)2 as temperature increases, which must be taken into consideration in the selection of the retention time for the design of process vessels in which bitumen-water or heavy-oil-water emulsions are to be treated with CaO. Addition of CaO into such emulsions reduces the activity of water-soluble naphthenic or asphaltic acids (denoted by the formula HA, in which A− represents the anionic naphthenic and asphaltic acid group acting as surfactant, and H+ is the acidic proton) and naphthenic or asphaltic acid salts such as sodium salts (NaA) by precipitating them in the form of water-insoluble calcium naphthenates or asphaltates (CaA2) in accordance with the following reactions:


2HA+Ca(OH)2→←CaA2+2H2O   (Equation 4)


2NaA+Ca(OH)2→←CaA2+2NaOH   (Equation 5)

The use of CaO as a process additive for destabilization of bitumen-water or heavy-oil-water emulsions provides advantages of improved water chemistry by reducing bicarbonate hardness of the recovered water in accordance with the following reaction:


Ca(HCO3)2+Ca(OH)2→←2CaCO3+2H2O   (Equation 6)

The use of CaO (which becomes Ca(OH)2 in aqueous environments) as a process additive for destabilization of bitumen-water or heavy-oil-water emulsions also promotes the advantageous result of flocculating water-wet sodium clay (Clay-Na) dispersed in water by the following ion exchange reaction:


Clay-Na+Ca(OH)2→←(Clay)2+2NaOH   (Equation 7)

by which the water-wet sodium clay, which easily disperses in water, is transformed into calcium clay, which does not tend to associate with water. Eventually, the clay particles flocculate as calcium clay and are thus separated out from the emulsion.

Furthermore, any excess amount of Ca(OH)2 added into the emulsions would be buffered by carbon dioxide (CO2), including the CO2 present in the atmosphere, in accordance with the following reaction:


Ca(OH)2+CO2H→←CaCO3+2H2O   (Equation 8)

However, excessive treatment of the emulsions or recovered water with CO2 would promote the formation of water-soluble bicarbonates in accordance with the following reaction:


CaCO3+CO2+H2O→←Ca(HCO3)2   (Equation 9)

which may be disadvantageous for purposes of recycling of recovered water to bitumen or oil production plants. Therefore, it will be prudent to monitor the pH of the emulsion and the recovered water when treating bitumen-water or heavy-oil-water emulsions and/or recovered water with CO2; more specifically, it will be desirable to monitor the pH and water chemistry.

Laboratory Testing

In laboratory tests conducted by the inventors, two bitumen-water emulsions produced by a SAGD process were analyzed using the Dean-Stark extraction apparatus. It was observed that one of these emulsions contained about 14% bitumen and the other emulsion contained about 28% bitumen; both emulsions contained about 0.3% fines, with the remainder of both emulsions being water. Analyses of bitumen samples recovered from these emulsions showed that the bitumen in both samples comprised about 19% saturates, 46% aromatics, 15% resins, and 20% asphaltenes (all on mass basis). The chemistry of the water recovered from the test emulsions by centrifugation (for example, without adding any chemical additive) is presented in Table 1.

TABLE 1 Chemical analysis of the water recovered from bitumen-water emulsion HCO3− Mg2+ Ca2+ Na+ K+ NH4+ Cl− SO42− pH (mg CaCO3/L) (mg/L) (mg/L) (mg/L) (mg/L) (mg/L) (mg/L) (mg/L) 8.14 166 0.2 1 402 15 8.5 448 5

The high alkalinity (i.e., pH=8.14) indicated in Table 1 appears to be caused by bicarbonate species from the reservoir rock. Because of the alkaline nature of the process water, the naphthenic and asphaltic acids present in bitumen or heavy oil (more specifically in the asphaltenes fraction) become water soluble and act as surfactants reducing the interfacial tension between bitumen and water and thereby promoting stability of the bitumen-water emulsion. The test emulsions most likely formed during the flow of immiscible bitumen and water through the reservoir sand matrix under the pressure drop created by gravity and applied pressure difference between the SAGD steam injection and production wells. If the emulsion formation was caused by surfactant behavior of the naphthenic and asphaltic acids present in bitumen asphaltenes, then:

    • (1) reducing pH of the emulsion (for example, by addition of hydrochloric acid—HCl) should destabilize the emulsion by shifting the equilibrium of HA→←A−+H+ towards HA (HA being the naphthenic or asphaltic acid; A− being the anionic naphthenic and asphaltic acid group acting as surfactant; and H+ being the acidic proton);
    • (2) increasing the pH of the emulsion (for example, by addition of sodium hydroxide (NaOH) or a mild basic salt such as sodium bicarbonate (NaHCO3)) should further stabilize the emulsion or not affect the stability of the emulsion;
    • (3) increasing Ca2+ concentration (for example, by addition of calcium chloride (CaCl2)) should destabilize the emulsion in accordance with the reaction 2A−+Ca2+→←CaA2, thereby reducing the activity of A− functional groups that act as surfactants; and
    • (4) increasing Ca2+ concentration (for example, by addition of CaO (lime)) should destabilize the emulsion by the same reason explained in point (3) immediately above.

Emulsion destabilization experiments performed using HCl, NaHCO3, CaCl2, and CaO (Ca(OH)2 in aqueous systems) as additives corroborated the four theses presented above: the addition of CaO, CaCl2, and HCl all destabilized the emulsions, while the addition of NaOH and NaHCO3 appeared to increase emulsion stability.

The present disclosure has focused on the use of CaO as a process additive, since CaO has been found to have the capacity to improve process water chemistry, to precipitate naphthenates and asphaltates, and to promote flocculation of clay particles by the chemical reactions expressed in Equations (4), (5), (6) and (7).

The most effective dosages of CaO for methods and processes in accordance with the present disclosure appear to be in the range of about 2.5 to about 3.0 grams of CaO per kilogram of emulsion. However, the dosage of CaO addition could be adjusted for the specific needs of the process applications. Depending on the chemical characteristics of a particular emulsion (including considerations such as bicarbonate content and pH), an appropriate and effective CaO dosage could be in the range between about 50 milligrams to about 5.0 grams per kilogram of emulsion. Injection of an inert gas such as nitrogen (N2) or other unreactive gas reduces the time required for the destabilization of the emulsion and recovery of bitumen or oil and water as separate streams.

Laboratory tests showed that methods and processes in accordance with the present disclosure work better as process temperature increases. This may be particularly advantageous in the context of field operations where emulsions are produced at elevated temperatures and pressures depending on the reservoir characteristics. Bitumen-water emulsions produced in SAGD processes will typically be at a temperature of about 210° C. (410° F.) and at pressure of about 1.6 megaPascals (220 psia). Accordingly, methods and processes in accordance with the present disclosure could be applied with high-temperature bitumen-water emulsions.

In this patent document, any form of the word “comprise” is to be understood in its non-limiting sense to mean that any item following such word is included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element. Wherever used in this document, the terms “typical” and “typically” are to be interpreted in the sense of representative or common usage or practice, and are not to be understood as implying invariability or essentiality.

Claims

1. A method for destabilizing an emulsion selected from the group consisting of bitumen-water emulsions and heavy-oil-water emulsions, said method comprising the step of treating the emulsion with a salt of a Period Table Group II earth alkali metal cation selected from the group consisting of cations of magnesium, calcium, strontium, and barium.

2. A method for destabilizing an emulsion selected from the group consisting of bitumen-water emulsions and heavy-oil-water emulsions, said method comprising the step of treating the emulsion with a salt of a metal cation selected from the group consisting of cations of aluminum, iron, and zinc.

3. A method for destabilizing an emulsion selected from the group consisting of bitumen-water emulsions and heavy-oil-water emulsions, said method comprising the step of treating the emulsion with an additive selected from the group consisting of hydrochloric acid (HCl), sodium bicarbonate (NaHCO3), calcium chloride (CaCl2), and calcium oxide (CaO).

4. A method as in claim 3 wherein the additive comprises lime in the form of calcium oxide (CaO).

5. A method as in claim 4 wherein the dosage of calcium oxide in the range between about 50 milligrams per kilogram of emulsion to about 5.0 grams per kilogram of emulsion.

6. A method as in claim 5 wherein the dosage of calcium oxide in the range between about 2.5 to about 5.0 grams per kilogram of emulsion.

7. A method as in claim 3, comprising the further step of injecting an unreactive gas into the emulsion to form a bitumen-rich or heavy-oil-rich froth.

8. A method as in claim 7 wherein the unreactive gas is selected from the group consisting of air, combustion flue gas, steam, nitrogen, and carbon dioxide.

9. A method as in claim 3 wherein the emulsion is a bitumen-water emulsion produced by an oil-sands-ore-water-slurry-based bitumen extraction process.

10. A method as in claim 3 wherein the emulsion is a bitumen-water emulsion produced by a steam-assisted bitumen recovery process.

11. A method as in claim 10 wherein the steam-assisted bitumen recovery process is the steam-assisted gravity drainage (SAGD) process.

12. A method as in claim 10 wherein the steam-assisted bitumen recovery process is the cyclic steam stimulation (CSS) process.

Patent History
Publication number: 20140202928
Type: Application
Filed: Jan 18, 2014
Publication Date: Jul 24, 2014
Applicant: Apex Engineering Inc. (Edmonton, CA)
Inventors: Baki OZUM (Edmonton), Nikolas A. ROMANIUK (Edmonton)
Application Number: 14/158,786
Classifications
Current U.S. Class: With Treating Agent (208/188)
International Classification: C10G 33/04 (20060101);