WO2013184506A1

WO2013184506A1 - In situ extraction of oilsand with ammonia

Info

Publication number: WO2013184506A1
Application number: PCT/US2013/043599
Authority: WO
Inventors: Paul R. Hart
Original assignee: Champion Technologies, Inc.
Priority date: 2012-06-05
Filing date: 2013-05-31
Publication date: 2013-12-12
Also published as: RU2014153492A; RU2618798C2

Abstract

A method for recovering heavy oil or bitumen from an underground reservoir by injection of anhydrous ammonia gas at a temperature greater than the temperature of the reservoir and a pressure such that the ammonia gas fills voids left by recovered oil and condenses to liquid as the gas cools from contact with the reservoir. The ammonia reacts with native naphthenic acids in the oil to form surfactants. These surfactants emulsify the oil into the immiscible liquid ammonia, which flows into a producing well that carries the emulsified fluid to the surface. The fluid may be depressurized to release the oil and recover the ammonia as a gas that may be recycled. The process requires no water supply, no water treatment, no water disposal, less heat than generating steam, and is compatible with oil-wet, acid-soluble, carbonate-type formations.

Description

IN SITU EXTRACTION OF OILSAND WITH AMMONIA

BACKGROUND

Field of the Invention

[0001] The present invention relates to methods of extracting oil from a subterranean formation.

Background of the Related Art

[0002] Enormous hydrocarbon reserves exist in the form of heavy oil and oil sand bitumen which does not flow out of the ground on its own. In the case of oil sand, the bitumen is not even pooled in the reservoir but distributed as tarry particulates around and between particles of silt and sand.

[0003] Consequently, one of the first methods of recovering such bitumen was to scoop up the sand, typically bearing 10 to 15% oil, in open pit mines, use warm to hot (40-90°C) water to wash the sand and silt back into the pit, and then use a hydrocarbon solvent to dissolve and transport the bitumen, purifying it in a series of arduous separation steps. This process consumes large amounts of fresh water and leaves behind enormous tailings ponds and a cratered landscape.

[0004] A more recent process separates the oil and sand in situ by injecting 500°C steam through an upper, horizontal well at a pressure such that the steam displaces oil and condenses to liquid water as it cools from contact with the reservoir. Native surfactants in the oil help emulsify the bitumen particles into the hot (150-180°C) condensed water, which drains into a lower, horizontal, producing well, which carries bitumen-containing water to the surface. This process is known as steam assisted gravity drainage or SAGD.

[0005] Once on the surface, the oil and water are chemically demulsified and separated by density, in most cases after diluting the bitumen in a hydrocarbon solvent. The water is chemically and physically treated in a series of arduous purification processes, so that most of it (80-95%) can be heated back into steam to be re-injected. [0006] This SAGD process does not disrupt the surface as much as pit mining, but still consumes fresh make-up water and generates waste water containing dissolved and precipitated organic and mineral solids. These solids must be removed from the water and disposed of by land fill or deep well injection in order to make the water back into steam for reinjection. This water purification process is difficult and expensive.

[0007] The production of steam also consumes enormous amounts of energy. According to the Canadian National Energy Board, SAGD production in Alberta, Canada, alone currently burns about 600 million cubic feet of natural gas to turn 1.8 million barrels of water into steam every day. Future production in Canada, considering all facilities currently operating, in construction, approved, or officially announced is about 7 times larger than the current volumes. A process to get the same oil production using no water and less heat would be far more economical and ecological.

[0008] Moreover, not all oilsand formations can employ SAGD. While the process has been very successful on water-wet, acid-insoluble silicateous formations, it has not been shown to work on the much larger deposits in oil-wet, acid-soluble, carbonate-type formations.

[0009] Heavy crude oil and bitumen in particular is enriched in polar compounds. One particular class of polar compound comprises large, polycyclic, carboxylic acids, commonly called "naphthenic acids". These polar compounds are surface active and disproportionately reside at the oil's interface with the formation minerals or water. These anionic surfactants generally make anionic silicate minerals water- wet, but render cationic carbonate minerals oil-wet.

[0010] One experimental, non-aqueous, alternative to SAGD is vapor extraction, which is sometimes referred to as "VapEx". This process uses hydrocarbon solvents instead of heat to reduce the viscosity of the bitumen underground. However, the viscosity of diluted bitumen is still many times higher than that of an emulsion of bitumen in water. Real production rates from vapor extraction have not been shown to be economical. Although VapEx does not consume water or require heat, as steam does, it loses expensive hydrocarbon solvent to the reservoir. BRIEF SUMMARY

[0011] One embodiment of the present invention provides a method for recovering oil from an underground reservoir. The method comprises injecting anhydrous ammonia gas into the underground reservoir at a temperature greater than the temperature of the reservoir and at a pressure that allows the ammonia gas to fill voids in the underground reservoir, wherein the oil in the underground reservoir causes the ammonia gas to condense to form an ammonia liquid in contact with the oil, and wherein the ammonia liquid reacts with components of the oil to form surfactants that support the formation of an oil-in- ammonia emulsion. The method further comprises removing the oil-in- ammonia emulsion from the underground reservoir.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

[0012] Figure 1 is a phase diagram for ammonia illustrating one set of conditions for practicing an embodiment of the present invention for liberating oil from mineral.

DETAILED DESCRIPTION

[0013] Embodiments of the present invention provide methods for liberating oil from mineral in situ by activating native surfactants to disperse the oil into an immiscible carrier fluid. More particularly, embodiments of the present invention may be employed as methods for recovering heavy oil or bitumen from an underground formation and transporting the heavy oil or bitumen through pipelines to a useful place.

[0014] One embodiment of the present invention includes a method of recovering heavy oil or bitumen from an underground formation. In this method, ammonia is injected underground to a reservoir of heavy crude oil. The injection temperature and pressure is such that the ammonia remains a gas all the way through the depleted formation to the oil production zone or draining front. Once there, the ammonia gas cools and condenses into a liquid, giving up its latent heat at a temperature warm enough to release oil from the formation mineral. The release temperature will depend on the viscosity of the native oil. For high viscosity oils, like bitumen, the release temperature can be lowered, if desired, by adding viscosity reducing solvents to the ammonia. Such solvents are well known and include hydrocarbons such as propane, hexane, gas condensate, and light naphtha.

[0015] In the condensation zone, the liquid ammonia reacts with the carboxylic acid groups of the native naphthenic acids that reside on the surface of the crude oil or bitumen, This creates powerful anionic surfactants (soaps) in situ at the bitumen- ammonia interface. The surfactants so formed accelerate the release (or inhibit the adsorption) of the oil from the mineral it encapsulates, break up the oil into smaller particles, and stabilize those particles in low-viscosity, oil-in-ammonia dispersions or emulsions.

[0016] The hydrophobic, hydrocarbon portion of the ammonium naphthenates so formed also adsorbs onto the surface of any oil-wet formation mineral. The hydrophilic, ionic, ammonium carboxylate groups then face out into the fluid and render the surface of the mineral water-wet. The water-like, condensed ammonia carrier fluid is then able to flow more swiftly through the water- wet formation.

[0017] The condensed ammonia is able to carry a high loading of the surface-activated oil as an emulsion, for example containing from 10 to 50 weight percent crude oil in liquid ammonia. This high carrying capacity of the liquid ammonia accelerates the recovery of oil from underground formations, and reduces the amount of the ammonia carrier fluid that is needed to produce a barrel of oil. This reduces the energy, capital, operation, and fluid makeup costs.

[0018] In various embodiments, the ammonia may be introduced through an injection well and the oil-containing emulsion may be removed through a production well. The injection and production wells might be the same well used successively, or two different wells. Where two different wells are used, either one or both of the wells may be vertical or horizontal. [0019] Once the oil has been carried to the surface, the ammonia carrier fluid may be recovered by low temperature vaporization. The ammonia gas may then be recompressed and heated for reinjection. This eliminates the use of water, water treatment, oil-water phase separation, waste water disposal, high temperature steam production, and all of the economic and environmental costs associated with these processes.

EXAMPLE

[0020] Figure 1 is an ammonia phase diagram illustrating one set of conditions for practicing a method for liberating oil from mineral in accordance with one embodiment of the present invention. This figure shows the physical state of ammonia as a function of temperature and pressure. At higher pressures and lower temperatures, ammonia is a liquid. At lower pressures and higher temperatures, ammonia is a gas. The dividing line between these two regions of the diagram is the condensation boundary.

[0021] In this example, ammonia is heated to 100°C, compressed to 170 psi, and injected (see "Injection" point in Figure 1) through a well into an underground oil reservoir. This displaces or fills the void left by oil removed from the reservoir. The arrow (leaving the "Injection" point in Figure 1) shows that as the injected ammonia gas transits the depleting or depleted reservoir, the ammonia gas loses mostly pressure at first, as it is impeded (section labeled "Void Filling, Displacement"), and then them ammonia gas loses mostly temperature, as it warms the more recently exposed rock. At about 50°C and 108 psi, the ammonia gas contacts the oil left in the reservoir, where it crosses the phase boundary, condensing to liquid and releasing its substantial latent heat. This heat warms the 20°C reservoir to 40-50°C, a temperature at which the viscosity of the oil is low enough to flow off the mineral and into the liquid ammonia. (This is the temperature, for example, used to release bitumen from oilsand in mining operations.) At this point the ammonia also reacts with the naphthenic acids on the surface of the oil to form ammonium naphthenate soaps that water-wet the mineral surface and emulsify the oil into the liquid ammonia (section labeled "Condensation, Emulsification" point in Figure 1). The oil-in- ammonia emulsion then flows through the reservoir to the producer well (which may be a different well than the injection well or, in a cyclic operation, the same well previously used as the injection well). As the oil-in- ammonia emulsion flows to the surface, the pressure and temperature drop somewhat to 30°C and 90 psi, as shown by the arrow labeled "Liquid Flow (Production)".

[0022] Once on the surface, the pressure on the oil-in- ammonia emulsion is reduced to about 65 psi, which causes the ammonia to evaporate back to a gas, cooling the ammonia gas to about 20°C, as shown by the arrow labeled "Evaporation (Recovery)". If necessary, a diluent can be added to the oil or bitumen at this point or earlier in order to lower the oil or bitumen viscosity and keep it flowing. Finally, the ammonia may be recompressed to 170 psi, reheated to 100°C and re-injected into the formation, completing the cycle, as shown by the upward arrow labeled "Recompression & Reheat (Reuse)".

[0023] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, the singular forms "a", "an" and "the" are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms "comprises" and/or "comprising," when used in this specification, specify the presence of stated features, integers, steps, operations, elements, components and/or groups, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. The terms "preferably," "preferred," "prefer," "optionally," "may," and similar terms are used to indicate that an item, condition or step being referred to is an optional (not required) feature of the invention.

[0024] The corresponding structures, materials, acts, and equivalents of all means or steps plus function elements in the claims below are intended to include any structure, material, or act for performing the function in combination with other claimed elements as specifically claimed. The description of the present invention has been presented for purposes of illustration and description, but it is not intended to be exhaustive or limited to the invention in the form disclosed. Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the invention. The embodiment was chosen and described in order to best explain the principles of the invention and the practical application, and to enable others of ordinary skill in the art to understand the invention for various embodiments with various modifications as are suited to the particular use contemplated.

Claims

CLAIMS What is claimed is:

1. A method for recovering oil from an underground reservoir, comprising:

injecting anhydrous ammonia gas into the underground reservoir at a temperature greater than the temperature of the reservoir and at a pressure that allows the ammonia gas to fill voids in the underground reservoir, wherein the oil in the underground reservoir causes the ammonia gas to condense to form an ammonia liquid in contact with the oil, and wherein the ammonia liquid reacts with components of the oil to form surfactants that support the formation of an oil-in-ammonia emulsion; and

removing the oil-in-ammonia emulsion from the underground reservoir.

2. The method of claim 1, further comprising:

depressurizing the oil-in-ammonia emulsion to vaporize the ammonia back to an ammonia gas; and

collecting the ammonia gas.

3. The method of claim 2, further comprising:

pressurizing and heating the collected ammonia gas; and

reinjecting the pressurized and heated ammonia gas into the underground reservoir at a temperature greater than the temperature of the reservoir and at a pressure that allows the ammonia gas to fill voids in the underground reservoir.

4. The method of claim 1, wherein the ammonia gas is injected into the underground reservoir through an injection well and the oil-in-ammonia emulsion is removed through a production well.

5. The method of claim 4, wherein the injection well and the production well are the same well.

6. The method of claim 4, wherein the injection well and the production well are separate wells, and wherein the injection and production wells are independently selected from vertical wells and horizontal wells.

7. The method of claim 1, wherein the underground reservoir includes an oil- wet, acid- soluble, carbonate-type formation.

8. The method of claim 1, wherein the oil-in-ammonia emulsion contains from 10 to 50 weight percent crude oil in liquid ammonia.