SYSTEMS AND METHODS FOR PRODUCING OIL AND/OR GAS

Abstract

A system for producing oil and/or gas from an underground formation comprising a well above the formation; a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation comprising water and an additive; and a mechanism to produce oil and/or gas from the formation.

Description

FIELD OF THE INVENTION

The present disclosure relates to systems and methods for producing oil and/or gas.

BACKGROUND OF THE INVENTION

Enhanced Oil Recovery (EOR) may be used to increase oil recovery in fields worldwide. There are three main types of EOR, thermal, chemical/polymer and gas injection, which may be used to increase oil recovery from a reservoir, beyond what can be achieved by conventional means—possibly extending the life of a field and boosting the oil recovery factor.

Thermal enhanced recovery works by adding heat to the reservoir. The most widely practiced form is a steam drive, which reduces oil viscosity so that it can flow to the producing wells. Chemical flooding increases recovery by reducing the capillary forces that trap residual oil. Polymer flooding improves the sweep efficiency of injected water. Miscible injection works in a similar way to chemical flooding. By injecting a fluid that is miscible with the oil, trapped residual oil can be recovered.

Referring to FIG. 1, there is illustrated prior art system 100. System 100 includes underground formation 102, underground formation 104, underground formation 106, and underground formation 108. Production facility 110 is provided at the surface. Well 112 traverses formations 102 and 104, and terminates in formation 106. The portion of formation 106 is shown at 114. Oil and gas are produced from formation 106 through well 112, to production facility 110. Gas and liquid are separated from each other, gas is stored in gas storage 116 and liquid is stored in liquid storage 118.

U.S. Pat. No. 5,826,656 discloses a method for recovering waterflood residual oil from a waterflooded oil-bearing subterranean formation penetrated from an earth surface by at least one well by injecting an oil miscible solvent into a waterflood residual oil-bearing lower portion of the oil-bearing subterranean formation through a well completed for injection of the oil miscible solvent into the lower portion of the oil-bearing formation; continuing the injection of the oil miscible solvent into the lower portion of the oil-bearing formation for a period of time equal to at least one week; recompleting the well for production of quantities of the oil miscible solvent and quantities of waterflood residual oil from an upper portion of the oil-bearing formation; and producing quantities of the oil miscible solvent and waterflood residual oil from the upper portion of the oil-bearing formation. The formation may have previously been both waterflooded and oil miscible solvent flooded. The solvent may be injected through a horizontal well and solvent and oil may be recovered through a plurality of wells completed to produce oil and solvent from the upper portion of the oil-bearing formation.

PCT Patent Application Publication WO 2010/02693 discloses a method comprising recovering a carbon source from a formation; converting at least a portion of the carbon source to a synthesis gas; converting at least a portion of the synthesis gas to an ether; and injecting at least a portion of the ether into the formation.

PCT Patent Application Publication WO 2008/141051 discloses a system for producing oil and/or gas from an underground formation including a well above the formation; a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation including dimethyl ether; and a mechanism to produce oil and/or gas from the formation.

There is a need in the art for improved systems and methods for enhanced oil recovery. There is a further need in the art for improved systems and methods for enhanced oil recovery using a water flood. There is a further need in the art for improved systems and methods for improving the operation and recovery factor from a water flood.

SUMMARY OF THE INVENTION

In one aspect, the invention provides a system for producing oil and/or gas from an underground formation comprising a well above the formation; a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation comprising water and an additive; and a mechanism to produce oil and/or gas from the formation.

In another aspect, the invention provides a method for producing oil and/or gas comprising injecting water and an additive into a formation from a first well; and producing oil and/or gas from the formation from a second well.

Advantages of the invention include one or more of the following:

Improved systems and methods for enhanced recovery of hydrocarbons from a formation with an improved water flood.

Improved systems and methods for enhanced recovery of hydrocarbons from a formation with a water injectant containing an oil soluble or miscible additive.

Improved compositions and/or techniques for secondary recovery of hydrocarbons.

Improved systems and methods for enhanced oil recovery.

Improved systems and methods for enhanced oil recovery using a miscible additive in a water flood.

Improved systems and methods for enhanced oil recovery using water with a compound which is miscible with oil in place.

Improved systems and methods for maintaining formation pressure.

Improved systems and methods for maintaining production rates.

Improved systems and methods for increasing the life of a reservoir.

Improved systems and methods for boosting the oil recovery factor.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an oil and/or gas production system.

FIG. 2a illustrates a well pattern.

FIGS. 2b and 2c illustrate the well pattern of FIG. 2a during enhanced oil recovery processes.

FIGS. 3a-3c illustrate oil and/or gas production systems.

FIG. 4 illustrates an oil and/or gas production method.

FIG. 5 illustrates a list of suitable waterflood additives.

FIG. 6 illustrates a list of suitable waterflood additives.

FIG. 7 illustrates the incremental recovery with the use of a waterflood additive.

FIG. 8 illustrates the incremental recovery with the use of waterflood additives of different concentrations.

DETAILED DESCRIPTION OF THE INVENTION

FIGS. 2a, 2b, & 2c:

Referring now to FIG. 2a, in some embodiments, an array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

Each well in well group 202 has horizontal distance 230 from the adjacent well in well group 202. Each well in well group 202 has vertical distance 232 from the adjacent well in well group 202.

Each well in well group 204 has horizontal distance 236 from the adjacent well in well group 204. Each well in well group 204 has vertical distance 238 from the adjacent well in well group 204.

Each well in well group 202 is distance 234 from the adjacent wells in well group 204. Each well in well group 204 is distance 234 from the adjacent wells in well group 202.

In some embodiments, each well in well group 202 is surrounded by four wells in well group 204. In some embodiments, each well in well group 204 is surrounded by four wells in well group 202.

In some embodiments, horizontal distance 230 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, vertical distance 232 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, horizontal distance 236 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, vertical distance 238 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, distance 234 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, array of wells 200 may have from about 10 to about 1000 wells, for example from about 5 to about 500 wells in well group 202, and from about 5 to about 500 wells in well group 204.

In some embodiments, array of wells 200 is seen as a top view with well group 202 and well group 204 being vertical wells spaced on a piece of land. In some embodiments, array of wells 200 is seen as a cross-sectional side view with well group 202 and well group 204 being horizontal wells spaced within a formation.

Referring now to FIG. 2b, in some embodiments, array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

In some embodiments, a water flooding mixture is injected into well group 204, and oil is recovered from well group 202. As illustrated, the water flooding mixture has injection profile 208, and oil recovery profile 206 is being produced to well group 202.

In some embodiments, a water flooding mixture is injected into well group 202, and oil is recovered from well group 204. As illustrated, the water flooding mixture has injection profile 206, and oil recovery profile 208 is being produced to well group 204.

In some embodiments, well group 202 may be used for injecting a water flooding mixture, and well group 204 may be used for producing oil and/or gas from the formation for a first time period; then well group 204 may be used for injecting a water flooding mixture, and well group 202 may be used for producing oil and/or gas from the formation for a second time period, where the first and second time periods comprise a cycle.

In some embodiments, multiple cycles may be conducted which include alternating well groups 202 and 204 between injecting a water flooding mixture, and producing oil and/or gas from the formation, where one well group is injecting and the other is producing for a first time period, and then they are switched for a second time period.

In some embodiments, a cycle may be from about 12 hours to about 1 year, or from about 3 days to about 6 months, or from about 5 days to about 3 months. In some embodiments, each cycle may increase in time, for example each cycle may be from about 5% to about 10% longer than the previous cycle, for example about 8% longer.

In some embodiments, a water flooding mixture may be injected at the beginning of a cycle, and an immiscible enhanced oil recovery agent or a mixture including an immiscible enhanced oil recovery agent may be injected at the end of the cycle. In some embodiments, the beginning of a cycle may be the first 10% to about 80% of a cycle, or the first 20% to about 60% of a cycle, the first 25% to about 40% of a cycle, and the end may be the remainder of the cycle.

Referring now to FIG. 2c, in some embodiments, array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

In some embodiments, a water flooding mixture is injected into well group 204, and oil is recovered from well group 202. As illustrated, the water flooding mixture has injection profile 208 with overlap 210 with oil recovery profile 206, which is being produced to well group 202.

In some embodiments, a water flooding mixture is injected into well group 202, and oil is recovered from well group 204. As illustrated, the water flooding mixture has injection profile 206 with overlap 210 with oil recovery profile 208, which is being produced to well group 204.

Enhanced Oil Recovery Methods

The recovery of oil and/or gas with array of wells 200 from an underground formation may be accomplished by any known method. Suitable methods include subsea production, surface production, primary, secondary, or tertiary production. The selection of the method used to recover the oil and/or gas from the underground formation is not critical.

In some embodiments, oil and/or gas may be recovered from a formation into a well, and flow through the well and flowline to a facility. In some embodiments, enhanced oil recovery, water with the use of an added agent for example a surfactant, a polymer, and/or a miscible agent such as a dimethyl ether formulation or carbon dioxide, may be used to increase the flow of oil and/or gas from the formation.

Releasing at least a portion of the water flooding mixture and/or other liquids and/or gases may be accomplished by any known method. One suitable method is injecting the water flooding mixture into a single conduit in a single well, allowing the water flooding mixture to soak, and then pumping out at least a portion of the water flooding mixture with gas and/or liquids. Another suitable method is injecting the water flooding mixture into a first well, and pumping out at least a portion of the water flooding mixture with gas and/or liquids through a second well. The selection of the method used to inject at least a portion of the water flooding mixture and/or other liquids and/or gases is not critical.

In some embodiments, the water flooding mixture and/or other liquids and/or gases may be pumped into a formation at a pressure up to the fracture pressure of the formation.

In some embodiments, the water flooding mixture may be mixed in with oil and/or gas in a formation to form a mixture which may be recovered from a well. In some embodiments, a quantity of the water flooding mixture may be injected into a well, followed by another component to force the formulation across the formation. For example air, water in liquid or vapor form, carbon dioxide, other gases, other liquids, and/or mixtures thereof may be used to force the water flooding mixture across the formation.

In some embodiments, the water flooding mixture may be heated prior to being injected into the formation to lower the viscosity of fluids in the formation, for example heavy oils, paraffins, asphaltenes, etc.

In some embodiments, the water flooding mixture may be heated and/or boiled while within the formation, with the use of a heated fluid or a heater, to lower the viscosity of fluids in the formation. In some embodiments, heated water and/or steam may be used to heat and/or vaporize the water flooding mixture in the formation.

In some embodiments, the water flooding mixture may be heated and/or boiled while within the formation, with the use of a heater. One suitable heater is disclosed in copending U.S. patent application having Ser. No. 10/693,816, filed on Oct. 24, 2003, and having attorney docket number TH2557. U.S. patent application having Ser. No. 10/693,816 is herein incorporated by reference in its entirety.

FIGS. 3a & 3b:

Referring now to FIGS. 3a and 3b, in some embodiments of the invention, system 300 is illustrated. System 300 includes underground formation 302, underground formation 304, underground formation 306, and underground formation 308. Facility 310 is provided at the surface. Well 312 traverses formations 302 and 304, and has openings in formation 306. Portions 314 of formation 306 may be optionally fractured and/or perforated. During primary production, oil and gas from formation 306 is produced into portions 314, into well 312, and travels up to facility 310. Facility 310 then separates gas, which is sent to gas processing 316, and liquid, which is sent to liquid storage 318. Facility 310 also includes water flooding mixture storage 330. As shown in FIG. 3a, water flooding mixture may be pumped down well 312 that is shown by the down arrow and pumped into formation 306. Water flooding mixture may be left to soak in formation for a period of time from about 1 hour to about 15 days, for example from about 5 to about 50 hours.

After the soaking period, as shown in FIG. 3b, water flooding mixture and oil and/or gas is then produced back up well 312 to facility 310. Facility 310 is adapted to separate and/or recycle water flooding mixture, for example by a gravity separation, centrifugal separation, chemical absorption, and/or by boiling the formulation, condensing it or filtering or reacting it, then storing or transporting desirable liquids and gases, and re-injecting and/or disposing of undesirable liquids and gases, for example by repeating the soaking cycle shown in FIGS. 3a and 3b from about 2 to about 5 times.

In some embodiments, water flooding mixture may be pumped into formation 306 below the fracture pressure of the formation, for example from about 40% to about 90% of the fracture pressure.

In some embodiments, well 312, as shown in FIG. 3a, injecting into formation 306 may be representative of a well in well group 202, and well 312 as shown in FIG. 3b, producing from formation 306, may be representative of a well in well group 204.

In some embodiments, well 312 as shown in FIG. 3a, injecting into formation 306, may be representative of a well in well group 204, and well 312, as shown in FIG. 3b, producing from formation 306 may be representative of a well in well group 202.

FIG. 3c:

Referring now to FIG. 3c, in some embodiments of the invention, system 400 is illustrated. System 400 includes underground formation 402, formation 404, formation 406, and formation 408. Production facility 410 is provided at the surface. Well 412 traverses formation 402 and 404 has openings at formation 406. Portions of formation 414 may be optionally fractured and/or perforated. As oil and gas is produced from formation 406 it enters portions 414, and travels up well 412 to production facility 410. Gas and liquid may be separated, and gas may be sent to gas storage 416, and liquid may be sent to liquid storage 418. Production facility 410 is able to produce and separate water flooding mixture, which may be produced and stored in production/storage 430. Water flooding mixture is pumped down well 432, to portions 434 of formation 406. Water flooding mixture traverses formation 406 to aid in the production of oil and gas, and then the water flooding mixture, oil and/or gas may all be produced to well 412, to production facility 410. Water flooding mixture may then be recycled, for example by separating the water flooding mixture from the rest of the production stream, then re-injecting the formulation into well 432.

In some embodiments, a quantity of water flooding mixture or water flooding mixture mixed with other components may be injected into well 432, followed by another component to force water flooding mixture or water flooding mixture mixed with other components across formation 406, for example a liquid, such as water in gas or liquid form; water mixed with one or more salts, polymers, and/or surfactants; or a gas, such as air; carbon dioxide; other gases; other liquids; and/or mixtures thereof.

In some embodiments, well 412 which is producing oil and/or gas is representative of a well in well group 202, and well 432 which is being used to inject water flooding mixture is representative of a well in well group 204.

In some embodiments, well 412 which is producing oil and/or gas is representative of a well in well group 204, and well 432 which is being used to inject water flooding mixture is representative of a well in well group 202.

FIG. 4:

Referring now to FIG. 4, in some embodiments of the invention, method 500 is illustrated. Method 500 includes injecting a water flooding mixture indicated by a checkerboard pattern on the figure; injecting an immiscible enhanced oil recovery formulation indicated by diagonal pattern on the figure; and producing oil and/or gas from a formation indicated by white pattern on the figure.

Injection and production timing for well group 202 is shown by the top timeline, while injection and production timing for well group 204 is shown by the bottom timeline.

In some embodiments, at time 520, water flooding mixture is injected into well group 202 for time period 502, while oil and/or gas is produced from well group 204 for time period 503. Then, water flooding mixture is injected into well group 204 for time period 505, while oil and/or gas is produced from well group 202 for time period 504. This injection/production cycling for well groups 202 and 204 may be continued for a number of cycles, for example from about 5 to about 25 cycles.

In some embodiments, at time 530, there may be a cavity in the formation due to oil and/or gas that has been produced during time 520. During time 530, only the leading edge of cavity may be filled with a water flooding mixture, which is then pushed through the formation with an immiscible enhanced oil recovery formulation. Water flooding mixture may be injected into well group 202 for time period 506, then immiscible enhanced oil recovery formulation may be injected into well group 202 for time period 508, while oil and/or gas may be produced from well group 204 for time period 507. Then, water flooding mixture may be injected into well group 204 for time period 509, then immiscible enhanced oil recovery formulation may be injected into well group 204 for time period 511, while oil and/or gas may be produced from well group 202 for time period 510. This injection/production cycling for well groups 202 and 204 may be continued for a number of cycles, for example from about 5 to about 25 cycles.

In some embodiments, at time 540, there may be a significant hydraulic communication between well group 202 and well group 204. Water flooding mixture may be injected into well group 202 for time period 512, then immiscible enhanced oil recovery formulation may be injected into well group 202 for time period 514 while oil and/or gas may be produced from well group 204 for time period 515. The injection cycling of miscible and immiscible enhanced oil recovery formulations into well group 202 while producing oil and/or gas from well group 204 may be continued as long as desired, for example as long as oil and/or gas is produced from well group 204.

In some embodiments, oil and/or gas produced may be transported to a refinery and/or a treatment facility. The oil and/or gas may be processed to produced to produce commercial products such as transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. Processing may include distilling and/or fractionally distilling the oil and/or gas to produce one or more distillate fractions. In some embodiments, the oil and/or gas, and/or the one or more distillate fractions may be subjected to a process of one or more of the following: catalytic cracking, hydrocracking, hydrotreating, coking, thermal cracking, distilling, reforming, polymerization, isomerization, alkylation, blending, and dewaxing.

Waterflooding Mixture

In some embodiments, oil and/or gas may be recovered from a formation with a waterflooding mixture.

In some embodiments, the waterflooding mixture may include from about 50% to about 99% water, for example from about 60% to about 98%, from about 70% to about 97%, from about 80% to about 96%, or from about 90% to about 95%.

The selection of water used in the waterflooding mixture is not critical. Suitable water to be used in the mixture could be salt water or fresh water, for example water from a body of water off such as a sea, an ocean, a lake, or a river, from a water well, connate water produced from a subsurface formation, processed water from a city water supply, gray water from a city sewage treatment plant, or another water supply. In some embodiments, water used in the waterflooding mixture may be subjected to one or more processing steps, such as those disclosed in United States Patent Application Publication Number US 2009/0308609, which is herein incorporated by reference in its entirety, for example if water with a high salinity content will be used.

The waterflooding mixture may include one or more additives to increase its effectiveness, for example by boosting the oil recovery factor, by swelling the oil, by lowering the viscosity of the oil, by increasing the mobility of the oil, and/or by increasing the subsurface pressure in the formation.

In some embodiments, the waterflooding mixture may include from about 1% to about 50% additives, for example from about 2% to about 40%, from about 3% to about 30%, from about 4% to about 20%, or from about 5% to about 10%.

Suitable additives to be used with the waterflooding mixture include chemicals having a molar solubility in water of at least about 1%, for example at least about 2% or at least about 3%, up too fully miscible with water, and having an octanol-water partition coefficient of at least about 1, for example greater than about 1.3, greater than about 2, or greater than about 3.

In some embodiments, suitable waterflooding mixture additives are listed in the attached Table 1.

In some embodiments, suitable waterflooding mixture additives include alcohols, amines, pyridines, ethers, carboxylic acids, aldehydes, ketones, phosphates, quinones, and mixtures thereof, where the chemical has a molar solubility in water of at least about 1% and an octanol-water partition coefficient of at least about 1.

In some embodiments, suitable waterflooding mixture additives include ethers such as dimethyl ether, diethyl ether, and methyl-ethyl ether.

There are a number of chemicals that have a high solubility in water, which are in fact fully miscible in water, but which would not be suitable as a waterflooding mixture additive that because of their very low partitioning coefficient. In operation, it would be easy to mix these chemicals with water and inject them into a subsurface formation, but a negligible amount of the chemical would then be transferred to the crude oil. In practice, one of these chemicals with a high solubility and a low partitioning coefficient would barely boost the recovery factor as compared to a waterflood by itself.

Some examples of chemicals with a high solubility in water, and a low partitioning coefficient include amines, glycols, and alcohols such as:

tetraethylenepentamine
triethylene tetramine
sorbitol
diethylene triamine
ethylenediamine
tetraethylene glycol
triethylene glycol
glycerol
formamide
diethylene glycol
diethanolamine
ethylene glycol
monoethanolamine
pyruvic acid

There are also a number of chemicals that have a high partitioning coefficient, but which would not be suitable as a waterflooding mixture additive that because of their very low solubility in water. In operation, only a very small amount of these chemicals could be mixed with water and injected into a subsurface formation, so that only a negligible amount of the chemical would be transferred to the crude oil. In order to achieve a large amount of the chemical been transferred to the crude oil, a huge volume of water would have to be injected. In practice, one of these chemicals with a low solubility and a high partitioning coefficient would barely boost the recovery factor as compared to a waterflood by itself.

Some examples of chemicals with a low solubility in water, and a high partitioning coefficient include alkanes, alkenes, and aromatic hydrocarbons, such as:

n-hexadecane
n-pentadecane
n-heptadecane
n-eicosane
n-nonadecane
n-octadecane
n-tridecane
n-tetradecane
hexachlorobenzene
1-hexadecene
n-dodecane
1-pentadecene
1-tetradecene

1-heptadecanol

Immiscible Enhanced Oil Recovery Agents:

In some embodiments, suitable immiscible enhanced oil recovery agents include liquids or gases, such as water in gas or liquid form, air, nitrogen, mixtures of two or more of the preceding, or other immiscible enhanced oil recovery agents as are known in the art. In some embodiments, suitable immiscible enhanced oil recovery agents are not first contact miscible or multiple contact miscible with oil in the formation.

In some embodiments, a suitable immiscible enhanced oil recovery agents includes water. The selection of water used as the immiscible agent is not critical. Suitable water to be used could be salt water or fresh water, for example water from a body of water off such as a sea, an ocean, a lake, or a river, from a water well, connate water produced from a subsurface formation, processed water from a city water supply, gray water from a city sewage treatment plant, or another water supply. In some embodiments, water used as the immiscible agent may be subjected to one or more processing steps, such as those disclosed in United States Patent Application Publication Number US 2009/0308609, which is herein incorporated by reference in its entirety, for example if water with a high salinity content will be used.

In some embodiments, immiscible agents and/or water flooding mixtures injected into the formation may be recovered from the produced oil and/or gas and re-injected into the formation.

In one embodiment, after the injection of the water flooding mixture is stopped, there is a quantity of oil in the formation which has absorbed a quantity of waterflooding mixture additives. The oil is immobile and can not be recovered. In order to recover the waterflooding mixture additives, a quantity of water without any additives is injected into the formation of and exposed to the oil, which water will absorb the additives, and then the water additive mixture will be produced to the surface.

In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of at least about 0.01 centipoise, or at least about 0.1 centipoise, or at least about 0.5 centipoise, or at least about 1 centipoise, or at least about 2 centipoise, or at least about 5 centipoise. In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of up to about 500 centipoise, or up to about 100 centipoise, or up to about 50 centipoise, or up to about 25 centipoise.

Surface Processes:

In some embodiments, oil and/or gas may be recovered from a formation with a waterflooding mixture. In order to separate the production fluids, the liquids may be separated from the gases, for example using gravity based and/or centrifugal separators as are known in the art. Then, the liquids may be separated, where the water may be separated from the oil for example using gravity based and/or centrifugal separators as are known in the art. The gas, the oil and the water may still contain some waterflooding mixture additives. The oil made undergo a distillation process to flash the waterflooding mixture additives and light hydrocarbons. This mixture of the waterflooding mixture additives and light hydrocarbons may be added to the gas phase. The gas phase will then be exposed to the water which will preferentially pull out the waterflooding mixture additives and leave behind the light hydrocarbons. At the end of the process, most of the waterflooding mixture additives will have been removed from the oil and gas so that they can be exported, while the water mixed with the waterflooding mixture additives will be ready to be recycled into the same field or stored and used in another field.

Illustrative Embodiments

In one embodiment of the invention, there is disclosed a system for producing oil and/or gas from an underground formation comprising a well above the formation; a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation comprising water and an additive; and a mechanism to produce oil and/or gas from the formation. In some embodiments, the system also includes a second well a distance from the first well, wherein the mechanism to produce oil and/or gas from the formation is located at the second well. In some embodiments, the mechanism to inject is located at the well, and wherein the mechanism to produce oil and/or gas from the formation is located at the well. In some embodiments, the underground formation is beneath a body of water. In some embodiments, the system also includes a mechanism for injecting an immiscible enhanced oil recovery formulation into the formation, after the water and an additive has been released into the formation. In some embodiments, the additive comprises a chemical having a solubility in water of at least 1% (at atmospheric conditions) and a octanol-water partitioning coefficient of at least 1 (at atmospheric conditions). In some embodiments, the system also includes an immiscible enhanced oil recovery formulation selected from the group consisting of water in gas or liquid form, and mixtures thereof. In some embodiments, the well comprises an array of wells from 5 to 500 wells. In some embodiments, the mechanism to produce oil and/or gas from the formation is located at the well. In some embodiments, the additive comprises a chemical having a solubility in water of at least 2% at a pressure of 50 bars and a temperature of 25 degrees centigrade. In some embodiments, the additive comprises a chemical having a crude oil-water partitioning coefficient of at least 2 at a pressure of 50 bars and a temperature of 25 degrees centigrade.

In one embodiment of the invention, there is disclosed a method for producing oil and/or gas comprising injecting water and an additive into a formation from a first well; and producing oil and/or gas from the formation from a second well. In some embodiments, a mixture of the water and the additive comprises from about 50% to about 99% water (by moles). In some embodiments, the water and the additive is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when injection begins. In some embodiments, the method also includes converting at least a portion of the recovered oil and/or gas into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. In some embodiments, the underground formation comprises an oil having an API from 10 to 100. In some embodiments, the water further comprises a water soluble polymer adapted to increase a viscosity of the mixture. In some embodiments, the method also includes reducing a bubble point of the oil in the formation with the additive. In some embodiments, the method also includes increasing a swelling factor of the oil in the formation with the additive. In some embodiments, the method also includes reducing a viscosity of the oil in the formation with the additive. In some embodiments, the water and the additive is injected into a reservoir having a reservoir temperature of at least 100 degrees centigrade, for example at least 250 degrees centigrade, measured prior to when injection begins. In some embodiments, the underground formation comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy.

Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments of the invention, configurations, materials and methods without departing from their spirit and scope. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature.

EXAMPLES

Example 1

Report 090130

The comprehensive functionality of this setup was verified through three sets of coreflood experiments which were performed on Crude Sample A live crude oil saturated Berea cores at 5600 psi, 175 F. In the first coreflood, 43.8% oil recovery was accomplished by waterflood and 49.1% incremental oil recovery was achieved by following 3.8 pore volume 9.35% m (mole percentage) DME/watermixture flood. In the second and third corefloods, the impact of DME concentration in water on ultimate oil recovery was studied preliminarily.

Specifically designed for 1-1.5 inch diameter, 24 inch long core to minimize the end effect, the coreflood system can be applied both horizontally and vertically with maximum operating pressure of 7500 psi and maximum operating temperature of 300 F. The comprehensive functionality of this setup was verified through three sets of coreflood experiments:

#1. Waterflood followed by tertiary 9.35% m DME/waterflood

#2.2% m secondary DME/waterflood

#3.5% m secondary DME/waterflood

These corefloods were performed on Crude Sample A live crude oil saturated Berea core vertically under reservoir condition (5600 psi, 175 F).

Crude Sample A Live Crude Oil Preparation

Crude Sample A live crude oil was prepared: it was first filtered and then recombined with natural gas to reach the desired GOR of 1435.6 scf/STB (at 60 F) and bubble point pressure of 5157 psi. Potentially, the live crude oil sample in the transfer vessel may undergo phase separation during transportation. Therefore, the received live crude transfer cylinder was mounted on rocker and shaken at 175 F, 5600 psi continuously for 48 hours to ensure that the live crude sample was homogenous. Once finished, the transfer cylinder was installed in the coreood system.

DME/Water Mixture Preparation

Experimental study carried out indicates the solubility of DME in water is around 18% m at 100:11 C (212:20 F) and 5600 psi [6]. The result suggests we can target 10% m DME in brine in the first experiment.

30950 ppm nanofiltered brine was applied to prepare DME/water mixture. To prepare 10% m DME/water mixture, 142 cc brine was mixed with 57.5 cc DME under 1000 psi at room temperature. Therefore, actually 9.35% m DME/water mixture was prepared in a transfer vessel and the mixture was maintained under 5600 psi during lifetime to prevent phase separation. In the second and third corefloods, to study the impact of DME concentration in water on ultimate oil recovery, 2% m DME/water mixture was prepared by mixing 9.7 cc DME with 120 cc brine and 5% m DME/water mixture was synthesized by mixing 25 cc DME with 120 cc brine with same process.

Coreflood Apparatus

A comprehensive coreflood system was built to investigate the incremental oil recovery under real reservoir condition. The main components of the system are list below:

1. One coreflood cell. The cell is wrapped by insulating ceramic fiber and can be heated by silicone heater on top, middle and bottom section. The overburden fluid is water. This cell can be rotated to conduct both vertical and horizontal flood.

2. Three Isco Series D pumps. These Isco pumps have 100 cc capacity and 10,000 psi upper pressure limit, they are used to control confining stress, injection pressure and maintaining back pressure respectively.

3. Three transfer vessels. The inlet transfer vessels are filled with fluids to be injected into the core. Here, the injectants can be either live crude oil, brine or DME/brine mixture in our case. The outlet of coreflood cell is connected to a Temco 10,000 psi Back Pressure Regulator (BPR) and using a transfer vessel filled with argon gas for back pressure maintenance.

4. Effluent collection device. A stepping-valve controlled device (VICI EMHMA-CE) was installed to collect effluents in test tubes. The outlet was switched to different test tube automatically after every 0.1 pore volume brine or DME/brine mixture was injected. The produced gas was released from fluid and collected in the gas sampling bags. Totally 20 fluid samples and 20 gas samples can be collected in one cycle.

5. A computer-controlled data acquisition system. It is used to monitor and control the experiments and record the data files including pressure, volume and temperature etc.

Coreflood Procedure

Here, we chose Crude Sample A crude oil saturated Berea sandstone core (porosity 18%, permeability 100 mD) for coreflood experiments to prove the concept. As mentioned, three corefloods (#1-3) were carried out vertically in this study. These corefloods are:

#1. Waterflood followed by tertiary 9.35% m DME/waterflood

#2.2% m secondary DME/waterflood

#3.5% m secondary DME/waterflood

The sequence followed during core experiments are described below:

1. Berea cores, 1 inch diameter by 24 inch long, were cleaned by flushing with chloroform to remove any hydrocarbons followed by methanol to remove any salts present. The solvent in core slug was then removed by drying the core in oven at 100 C for 24 hours. Mass of dried pristine cores was measured.

2. Core was then sleeved using Teflon heat-shrink tubing, and loaded in a desaturation cell for brine saturation to determine pore volume (PV). Temperature of desaturation cell was first set at 75 F and 1150 psi overburden pressure was applied. Then, core was vacuumed and then saturated with synthesized Crude Sample A formation brine (116,382 ppm). In the laboratory condition, only divalent and monovalent salts are selected to make synthetic brine. The salts were purchased from Sigma-Aldrich Co. The brine was filtered through a 0.2 m PTFE filter and degassed prior to use. Accurate pore volume was measured during the brine saturation process.

3. Subsequently, brine in the core slug was displaced by Crude Sample A dead crude oil to achieve initial oil saturation condition using a 15 bar ceramic membrane. This step was carried out at a maximum rate of 1 cc/hour with 175 psi injection pressure applied for experiment #1 and #3 and 150 psi injection pressure applied for experiment #2. 25 psi back pressure was applied for all these experiments. The injection rate selection was based on the total pore volume and was kept low to allow the completion of flow experiments within reasonable time constraints. The process was conducted until there is no obvious increase in hydrocarbon pore volume. Accurate hydrocarbon pore volume and irreducible water saturation can be measured during the process. Following the drainage, temperature was increased to 175 F. The dead crude saturated core was aged for 4 weeks to achieve the restored state.

4. Afterwards, the dead oil saturated cores were transferred into the coreflood cell. Before transferring, dead crude oil saturated cores were further wrapped by Teflon tape followed by aluminium foil. The end piece pistons were designed with o-ring grooves. Then, both pistons and aluminium foil wrapped cores were packed by thick heat-shrink Teflon tubing. The force on o-ring exerted by heat shrink tubing provided seal around end-pieces.

5. Then, dead crude in the core slug was displaced with 2 pore volume synthesized Crude Sample A live crude oil at a flow rate of 1 cc/hr. During this process, temperature of coreflood cell and live crude oil cylinder was set at 175 F, confining pressure was set to 6600 psi with the pore pressure set at 5600 psi giving an effective stress of 1000 psi. The effluents passed through BPR and multi-position actuator controlled device and finally collected in the test tubes.

6. After live crude displacement, the inlet was connected to the transfer vessel filled with coreflood injectants (Water or DME/Water mixture). The core floods were carried out at a flow rate of 1 cc/hr. The produced fluids were collected in the test tubes. Most of gas was released from produced fluids at ambient condition, then collected in the sample bags for composition analysis to understand the recovery process. As mentioned above, totally 20 liquid samples and 20 gas samples were collected in one cycle.

7. Once the corefloods were finished, the pore pressure was decreased to ambient condition, whereas part of residual oil was blow down and collected. Core slugs were then baked in oven at 100 C for 24 hours to obtain the remaining oil mass. The addition of blow-down oil volume to remaining oil volume gave irreducible oil volume.

Ultimate Recovery Factor

The whole experiments were controlled and monitored by computer. Pressure, volume, flow rate, and temperature were recorded every 1 minute. The mass balance was calculated once the experiment was finished. As previously described, most of the residue oil in the core slug was blow down. The core slug was then transferred to oven and dried at 100 C for 24 hours to measure the remaining oil. The Table is a summary, at the end of the coreflood, the mass balance was near 100% as mass balance of oil in each step was performed. In experiment #1, totally about 92.9% oil recovery was achieved through waterflood and subsequent 9.35% m DME/waterflood.

No visible residue oil was observed from core slug after 9.35% m tertiary DME/Water coreflood. In experiment #2 and #3, 52.5% and 71.5% ultimate oil recovery were accomplished respectively.

Since effluents were collected in test tubes, whereas gas samples were phase separated from the liquid phase and collected in gas sample bags, the recovery factors at each step were calculated as a function of injected hydrocarbon pore volume. The graph shows recovery factor curves, produced GOR and DME concentration in produced gas as a function of injected

Summary of Coreflood Experiments.

	Corefloods	Corefloods	Corefloods
Parameter	# 1	# 2	# 3
Pore Volume (cc)	51.35	51.37	53.04
Hydrocarbon Pore Volume	38.69	33.27	38.62
(cc)
Formation Volume Factor	1.56	1.44	1.50
(FVF)
Initial Oil Saturation (%)	75.35	64.8	72.8
Irreducible Water Saturation	24.65	35.2	27.2
(%)
Blowdown dead Oil Volume	0.75	6.7	5
(cc)
Remaining dead Oil Volume	1.23	4.12	2.55
(cc)
Produced dead Oil Volume	23.04	12.14	18.4
(cc)
Ultimate Oil Recovery	92.9%	52.5%	71.5%

hydrocarbon pore volume from experiment #1. Waterflood achieved about 43.8% oil recovery (secondary recovery) and water breakthrough was observed after about 0.46 hydrocarbon pore volume brine injection. After 1.1 hydrocarbon pore volume injection, the inlet was switched to 9.35% m DME/water mixture cylinder and 9.35% m DME/Waterflood finally achieved 49.1% incremental oil recovery with 5 hydrocarbon pore volume injection (tertiary recovery). During tertiary flood, collected gas after 1.50, 2.31, 2.85, 4.21, 5.31 and 5.90 hydrocarbon pore volume injection were selected for Gas Chromatography (GC) analysis. GC analysis indicated that the more DME/Water injection, the higher DME concentration in produced gas, which was consistent with produced GOR data.

FIG. 7 shows the results of the 9.35% m DME/Waterflood where the waterflood recovery plateaus at around 45%, then additional recovery is achieved with the use of the 9.35% m DME/Waterflood mixture.

Additionally, experiment #2 and #3 were carried out to study the impact of DME concentration in water on ultimate oil recovery. The graph shows the recovery curve as a function of injected hydrocarbon pore volume. Obviously, DME/waterflood kept producing crude oil even after breakthrough. Basically, the more DME/water mixture was injected and the higher DME concentration in water, the higher ultimate oil recovery. Finally, 2.91 hydrocarbon pore volume 2% m DME/water injection achieved 52.5% ultimate oil recovery. 2.5 hydrocarbon pore volume 5% m DME/water injection accomplished 71.5% ultimate oil recovery

FIG. 8 shows the results of the 2% m DME/Waterflood compared to the results of the 5% m DME/Waterflood.

Example 2

Report 020810

Two long core flooding experiments, were carried out on Berea sandstone cores restored using Crude Sample C crude oil (viscosity 65 cp). Both experiments use a DME enhanced waterflood in tertiary mode. The concentration of DME in the injection stream is 9.35% m. The experiment #1 is a continuous injection of 7 PV DME/Water mixture after initial waterflood, after DME enriched waterflood, we switched back to pure waterflood. During the whole process 92% oil recovery is achieved. For comparison, only 1 PV DME/Water mixture was injected after conventional waterflood in the experiment #2.28% incremental recovery is achieved during DME/Water slug injection.

	Crude	Crude	Crude
	Sample A	Sample B	Sample C
Bubble Point [psi]	5188	3538	1071
Molecular Weight [kg/kmol]	97.2	145.54	287.58
ρ [kg/m3]	731.1	840.4	865
μ [cP] at Bubble Point	0.543	5.744	65
Reservoir Temperature [° F.]	175	135	115
Reservoir Pressure [psi]	5500	3500	1350
Gas Oil Ratio [cc/cc]	251.33	91.84	23

Two core floods were carried out on 100 mD Berea sandstone cores restored using Crude Sample C crude oil and synthesized brine. They are: #1 Water flood followed by 7 PV 9.35% m DME/Water flood followed by water flood #2 Water flood followed by 1 PV 9.35% m DME/Water flood followed by water flood

For both experiments, initial water flood can generally produce 45% OOIP.

For experiment #1, after water flood, we kept injecting DME/Water mixture until the recovery curve flattens out. 45% incremental oil recovery has been achieved during this period. Further water flood after DME/Water flood swept small amount oil out very slowly (2%), which is not a big impact on ultimate oil recovery.

For experiment #2, only 1 PV DME/Water mixture was injected after conventional waterflood. 28% incremental recovery is achieved during DME/Water slug injection and following pure waterflood. 11% of these were produced after switching back to pure waterflood which was used to push the DME slug through core.

In addition, the comparison between experiments and the simulation shows that the main aspects of the recovery process are understood and can be simulated properly.

Crude Sample C live crude was prepared. Crude Sample C dead crude was first filtered and then recombined with natural gas to reach the desired GOR of 140.65 scf/STB (at 60 F). The saturation pressure of synthesized live crude is 1071 psia. Since the live crude oil sample may be phase separated during transportation, same recombination procedure used as described above was followed to ensure live crude sample is homogeneous before transferring to live crude cylinder in coreflood setup. PVT study of recombined Crude Sample C live crude shows its viscosity is 65 cp at saturation pressure.

Restored State Core Preparation

Restored state Berea sandstone cores (1″ diameter, 24″ long) were prepared using a 15 bar porous plate. Cores were first saturated with 116381 ppm synthesized brine under 1000 psi confining stress. Afterwards, brine was displaced with Crude Sample C dead crude to irreducible water saturation at a capillary pressure of 150 psi. Then, cores were aged at 115 F under stress for 28 days to achieve restored state.

DME/Water Mixture Preparation

30950 ppm nanofiltered brine was used to prepare DME/water mixture. To prepare 9.35% m DME/water mixture, 141.1 cc brine was mixed with 58.9 cc DME under 1350 psi at room temperature in a transfer vessel.

The coreflood set up has also been described in detail in earlier report, The system was designed with a maximum operating pressure of 7500 psi and maximum operating temperature of 300 F. In this study, we set the pore pressure at 1350 psi (reservoir pressure, above bubble point) and effective confining stress at 1000 psi. The temperature of both core holder and live crude cylinder was maintained at 115 F (reservoir temperature).

Once loaded into core holder, dead crude in the core plug was displaced with Crude Sample C live crude at a flow rate of 0.018 cc/min under reservoir conditions. During this process, effluent was collected in a graduate cylinder through a Temco backpressure regulator.

The pressure difference between inlet and outlet of core build up continuously until breakthrough, the system achieved equilibrium after around 1 PV live crude injection. P slightly goes up after 50 hours injection, which may be caused by temperature fluctuations.

The whole experiments were controlled and monitored by computer. Pressure, volume, flow rate, and temperature were recorded every 1 minute. The mass balance was calculated once the experiment was finished. Previously results on Crude Sample A live crude shows most of the residue oil in the core slug can be blown down. The formation factor of Crude Sample C live crude (1.08) is much less than the formation factor of Crude Sample A live crude (1.66). Therefore, no blowdown oil was observed during these two experiments. The core slug was then transferred to oven and dried at 100 C to measure the remaining oil.

Summary of coreood experiments.

Parameter	Coreoods # 1	Coreoods # 2
Pore Volume (cc)	53.04	51.35
Hydrocarbon Pore Volume (cc)	41.57	38.18
Formation Volume Factor (FVF)	1.06	1.06
Initial Oil Saturation (%)	78.37	74.35
Irreducible Water Saturation (%)	21.63	25.65
Blowdown dead Oil Volume (cc)	0	0
Remaining dead Oil Volume (cc)	4.64	10.90
Produced dead Oil Volume (cc)	36.35	25.99
Ultimate Oil Recovery	92%	73%

The mass balance should be close to 100%. The reality is, at the end, the mass balance was close to but slightly higher than 100% as mass balance of oil in each step was performed, especially for experiment #1. The obvious emulsion in some effluents is expected to be root cause of this slight overestimation.

In experiment #1, 45% oil recovery was achieved through initial waterflood, subsequent 9.35% m DME/water flood can give additional 45% incremental oil recovery. The following waterflood swept some additional oil out very slowly (2%), which is not a big impact on ultimate oil recovery.

In experiment #2, initial waterflood consistently achieved 45% oil recovery. To study the slug size sensitivity, only 1 PV of 9.35% DME/Water mixture was injected subsequently, 28% incremental recovery is achieved during DME/Water slug injection and following pure waterflood. 11% of these were produced after switching back to pure waterflood which was used to push the DME slug through core.

Continuous Injection Experiment #1

Since effluents were collected in test tubes, whereas gas samples were phase separated from the liquid phase and collected in gas sample bags, the recovery factors at each step were calculated as a function of injected hydrocarbon pore volume.

In the beginning the characteristic behavior for a conventional waterflood can be observed. The initial oil production is followed by some afterdrainage after water breakthrough. Water flood achieved about 45% oil recovery (secondary recovery) and water breakthrough was observed after about 0.4 hydrocarbon pore volume brine injection. For a rather viscous oil like Crude Sample C it is not surprising that a significant amount of oil is produced after water breakthrough during the afterdrainage.

After 4.2 hydrocarbon pore volume injection, the inlet was switched to 9.35% m DME/water mixture cylinder and this step finally achieved 45% incremental oil recovery after 9 hydrocarbon pore volume injection (tertiary recovery).

During tertiary flood, collected gas after 4.74, 6.33, 5.91, 7.60, 8.39 and 10.71 hydrocarbon pore volume injection were selected for Gas Chromatography (GC) analysis. GC analysis indicated that the more DME/Water injection, the higher DME concentration in produced gas, which was consistent with the trend of produced GIWR data.

After we switched back to pure water flood, GIWR decreased very quickly and further waterflood did not have big impact on improving oil recovery.

Slug Injection Experiment #2

The slug injection process will limit the total amount of DME used. The slug injection experiment shows similar behavior as experiment #1 before switching back to pure water flood. Initial waterflood consistently achieved 45% oil recovery. The tertiary slug injection (1 PV) and subsequent pure waterflood give 28% incremental oil recovery. 11% were produced after switching back to pure waterflood which was used to push the DME slug through core.

The oil production restarted after around 0.4 PV DME/water mixture injection. This is also consistent with the observation in experiment #1. The critical discovery here is the further waterflood can still recovery additional 11% OOIP.

After a steep initial pressure drop the curve levels out as the flow approaches a steady state. The initial pressure drop is caused by the fact that the viscous pressure drop is significantly lower than the initial viscous pressure drop needed to move the Crude Sample C oil through the core. The pressure drop during the afterdrainage is controlled by both the viscous and the capillary pressure. Even though for a viscous oil like Crude Sample C the capillary forces are less significant than for lighter oils, they cannot be completely neglected. After we switched to 9.35% m DME/water flood, P built up when DME started to diffuse from water phase to oil phase, during which these residue oil was swelled and oil saturation increases. This reduces the water mobility and increase the oil mobility.

Claims

1. A system for producing oil or gas from an underground formation comprising:

a well above the formation;

a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation comprising water and an additive comprising a chemical having a solubility in water of at least 1% (at atmospheric conditions) and a octanol-water partitioning coefficient of at least 1 (at atmospheric conditions); and

a mechanism to produce oil or gas from the formation.

2. The system of claim 1, further comprising a second well a distance from the first well, wherein the mechanism to produce oil or gas from the formation is located at the second well.

3. The system of claim 1, wherein the mechanism to inject is located at the well, and wherein the mechanism to produce oil or gas from the formation is located at the well.

4. The system of claim 1, wherein the underground formation is beneath a body of water.

5. The system of claim 1, further comprising a mechanism for injecting an immiscible enhanced oil recovery formulation into the formation after the water and an additive has been released into the formation.

6. (canceled)

7. The system of claim 1, further comprising an immiscible enhanced oil recovery formulation selected from the group consisting of water in gas or liquid form and mixtures thereof.

8. The system of claim 1, wherein the well comprises an array of wells from 5 to 500 wells.

9. The system of claim 1, wherein the mechanism to produce oil or gas from the formation is located at the well.

10. The system of claim 1 wherein the additive comprises a chemical having a solubility in water of at least 2% at a pressure of 50 bars and a temperature of 25 degrees centigrade.

11. The system of claim 1, wherein the additive comprises a chemical having a crude oil-water partitioning coefficient of at least 2 at a pressure of 50 bars and a temperature of 25 degrees centigrade.

12. A method for producing oil or gas comprising:

injecting water and an additive comprising a chemical having a solubility in water of at least 1% at atmospheric conditions and a octanol-water partitioning coefficient of at least 1 at atmospheric conditions into a formation from a first well; and

producing oil or gas from the formation from a second well.

13. The method of claim 12, wherein a mixture of the water and the additive comprises from about 50% to about 99% water by moles.

14. The method of claim 12, wherein the water and the additive is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when injection begins.

15. The method of claim 12, further comprising converting at least a portion of the recovered oil or gas into a material selected from the group consisting of transportation fuels, heating fuels, lubricants, chemicals, and polymers.

16. The method of claim 12, wherein the underground formation comprises an oil having an API from 10 to 100.

17. The method of claim 12, wherein the water further comprises a water soluble polymer adapted to increase a viscosity of the mixture.

18. The method of claim 12 further comprising reducing a bubble point of the oil in the formation with the additive.

19. The method of claim 12, further comprising increasing a swelling factor of the oil in the formation with the additive.

20. The method of claim 12, further comprising reducing a viscosity of the oil in the formation with the additive.

21. The method of claim 12, wherein the water and the additive is injected into a reservoir having a reservoir temperature of at least 100 degrees centigrade measured prior to when injection begins.

22. The method of claim 12, wherein the underground formation comprises a permeability from 0.0001 to 15 Darcies.