RU2574645C2 - Systems and methods of oil and/or gas production - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: invention is referred to oil and/or gas production. The specified water and additive represent a mixture containing approximately 50-99 mol % of water and additive containing simple dimethyl ether, simple diethyl ether or simple methyl ethyl ether. At that groups of wells are used. One group is used for reservoir flooding, while the second one is used for oil production during the first time period. Then groups of wells for reservoir flooding and oil production are changed during the second time period. The cycle is composed of the first and second time periods. Each cycle is increased in time per 5-10% in comparison with duration of the previous cycle. During first 10-80% of the cycle duration one mixture for reservoir flooding is injected with additives, during remaining time period of the cycle the other mixture for reservoir flooding is injected with additives including immiscible additives.

EFFECT: higher efficiency of extraction; method includes injection of water and additive to reservoir from the first well and oil and/or gas production from reservoir of the second well.

10 cl, 1 tbl, 12 dwg

Description

FIELD OF THE INVENTION

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

State of the art

Oil production using enhanced oil recovery (EOR) methods can be used to increase oil production at fields around the world. There are three main types of EOR, thermal, chemical / polymer methods and gas injection, which can be used to increase oil production from the reservoir beyond that which can be obtained by conventional means, possibly extending the life of the field and increasing the oil recovery coefficient.

Thermally stimulated production works by adding heat to the formation. The most widely used form is the displacement of oil by steam, which reduces the viscosity of the oil so that it can flow into production wells. Chemical water flooding increases production by reducing capillary forces that retain residual oil. Polymer flooding increases the displacement rate of injected water. Miscible fluid injection works in a manner similar to chemical flooding. By injecting a fluid that is miscible with oil, retained residual oil can be produced.

Turning to FIG. 1, a system 100 of the prior art is illustrated here. System 100 includes a subterranean formation 102, an underground formation 104, an underground formation 106, and an underground formation 108. Mining equipment 110 is provided at the surface. Well 112 passes through formations 102 and 104 and ends in formation 106. Part of formation 106 is shown as 114. Oil and gas are produced from formation 106 through well 112 in production equipment 110. Gas and liquid are separated from each other, gas is stored in a gas storage 116 and the liquid is stored in the storage 118 for liquid.

U.S. Pat. No. 5,826,656 describes a method for producing residual oil by flooding from a flooded oil-bearing subterranean formation through which at least one well passes from the surface of the earth by injecting a solvent miscible with oil into a flooded, residual oil-containing lower portion of the oil-bearing subterranean formation through a well completed to inject an oil miscible solvent into the lower portion of the oil reservoir; continuing to inject the oil-miscible solvent into the lower portion of the oil reservoir for a period of at least one week; re-completion of the well to obtain some amounts of a solvent miscible with oil and produce some amounts of flooded residual oil from the upper part of the oil reservoir; and obtaining certain amounts of a solvent miscible with oil and extracting residual oil from the top of the water-flooded oil reservoir. The reservoir can be either flooded with water or flooded with a solvent miscible with oil. The solvent can be injected through a horizontal well, and the solvent and oil can be recovered through a plurality of wells completed for oil production and solvent extraction from the upper part of the oil reservoir.

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

PCT Patent Application Publication WO 2008/141051 describes a system for producing oil and / or gas from an underground formation, including a well above the formation; a mechanism for injecting a composition to enhance oil recovery from a formation that contains dimethyl ether; and a mechanism for producing oil and / or gas from the formation.

There is a need in the art for improved oil production systems and methods using enhanced oil recovery methods. In addition, there is a need in the art for improved systems and methods for oil recovery using enhanced oil recovery methods using water injection. In addition, in this area there is a need for improved systems and methods for improving the performance and oil recovery from flooding.

Disclosure of invention

In one aspect, the present invention provides a system for producing oil and / or gas from an underground formation containing a well above the formation; a mechanism for injecting into the formation a composition for enhancing oil recovery, which contains water and an additive; and a mechanism for producing oil and / or gas from the formation.

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

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

Improved systems and methods for improved hydrocarbon production from the reservoir using improved waterflooding.

Improved systems and methods for improved hydrocarbon production from a formation using a water-based working agent containing an oil soluble or oil miscible additive.

Improved compositions and / or technologies for secondary hydrocarbon production.

Improved oil production systems and methods using enhanced oil recovery methods.

Improved systems and methods for oil production using enhanced oil recovery methods using a mixed additive in waterflooding.

Improved systems and methods for oil production using enhanced oil recovery methods using water together with a compound that is miscible with oil in situ.

Improved systems and methods for maintaining pressure in the reservoir.

Improved systems and methods to maintain production speed.

Improved systems and methods for increasing the reservoir lifetime.

Improved systems and methods for increasing oil recovery.

Brief Description of the Drawings

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

Figure 2a illustrates a well structure.

FIGS. 2b and 2c illustrate the well structure in FIG. 2a during enhanced oil recovery methods.

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

Figure 4 illustrates a method of producing oil and / or gas.

5 illustrates a list of suitable waterflooding additives.

6 illustrates a list of usable waterflooding additives.

7 illustrates the increase in production when using additives for flooding.

Fig. 8 illustrates an increase in production using various concentrations of waterflooding additives.

The implementation of the invention

Figa, 2b and 2c:

Turning now to FIG. 2a, here, in some embodiments, an arrangement of 200 wells is illustrated. The arrangement 200 comprises a group of 202 wells (indicated by horizontal lines) and a group of 204 wells (indicated by diagonal lines).

Each well in a group of 202 wells has a horizontal distance 230 from an adjacent well in a group of 202 wells. Each well in a group of 202 wells has a vertical distance of 232 from an adjacent well in a group of 202 wells.

Each well in group 204 wells has a horizontal distance of 236 from an adjacent well in group 204 wells. Each well in group 204 wells has a vertical distance of 238 from an adjacent well in group 204 wells.

Each well in group 202 wells is located at a distance of 234 from neighboring wells in group 204 wells. Each well in group 204 wells is located at a distance of 234 from neighboring wells in group 202 wells.

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

In some embodiments, the 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 it is about 100 meters.

In some embodiments, the 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 it is about 100 meters.

In some embodiments, the 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 it is about 100 meters.

In some embodiments, the 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 it is about 100 meters.

In some embodiments, implementation, the 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 it is about 100 meters.

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

In some embodiments, a well arrangement 200 is visible in plan view with a group of 202 wells and a group of 204 wells, which are vertical wells located at a distance from each other, on a piece of land. In some embodiments, a well spacing 200 is visible as a cross-sectional side view with a group of 202 wells and a group of 204 wells, which are horizontal wells spaced apart from each other in a formation.

Turning now to FIG. 2b, in some embodiments, an arrangement of 200 wells is illustrated. The arrangement 200 comprises a group of 202 wells (indicated by horizontal lines) and a group of 204 wells (indicated by diagonal lines).

In some embodiments, a waterflood mixture is injected into a group of 204 wells, and oil is produced from a group of 202 wells. As illustrated, the waterflooding mixture has an injection profile 208, and oil production profile 206 is obtained using a group of 202 wells.

In some embodiments, the flooding mixture is injected into a group of 202 wells, and oil is produced from a group of 204 wells. As illustrated, the waterflooding mixture has an injection profile 206, and oil production profile 208 is obtained using a group of 204 wells.

In some embodiments, a group of 202 wells may be used to inject the water flooding mixture, and a group of 204 wells may be used to produce oil and / or gas from the formation during a first period of time; then a group of 204 wells can be used to pump the mixture for waterflooding, and a group of 202 wells can be used to produce oil and / or gas from the formation during a second time period, with the first and second time periods making up a cycle.

In some embodiments, implementation, it is possible to carry out many cycles, which include switching groups 202 and 204 wells between injection of a mixture for waterflooding and oil and / or gas production, where one group of wells is injection and the second is production during the first period of time, and then they change places during the second period of time.

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, implementation, each cycle may increase over time, for example, each cycle may be approximately 5% - approximately 10% longer than the previous cycle, for example greater than about 8%.

In some embodiments, the waterflooding mixture may be injected at the beginning of the cycle, and the immiscible oil recovery agent using enhanced oil recovery methods or a mixture containing the immiscible oil recovery agent using enhanced oil recovery methods may be injected at the end of the cycle. In some embodiments, the start of the cycle may include the first about 10% -80% of the cycle, or the first about 20% -60% of the cycle, the first about 25% -40% of the cycle, and the end of the cycle may comprise the rest of the cycle.

Turning now to FIG. 2c, in some embodiments, an arrangement of 200 wells is illustrated. The arrangement 200 comprises a group of 202 wells (indicated by horizontal lines) and a group of 204 wells (indicated by diagonal lines).

In some embodiments, a waterflood mixture is injected into a group of 204 wells, and oil is produced from a group of 202 wells. As illustrated, the waterflooding mixture has an injection profile 208 that overlaps, 210, with an oil production profile 206 that is obtained using a group of 202 wells.

In some embodiments, the flooding mixture is injected into a group of 202 wells, and oil is produced from a group of 204 wells. As illustrated, the waterflooding mixture has an injection profile 206 that overlaps, 210, with an oil production profile 208 that is obtained using a group of 204 wells.

Oil production methods using enhanced oil recovery methods

Oil and / or gas can be extracted using 200 wells from an underground formation using any known method. Suitable methods for use include production from the bottom of the sea, production from the surface, primary, secondary or tertiary production. The selection of the method used to extract oil and / or gas from the subterranean formation is not critical.

In some embodiments, oil and / or gas may be produced from the formation in the well and flow through the well and pipe into equipment. In some embodiments, when producing oil using enhanced oil recovery methods, water using an added agent, such as a surfactant, a polymer, and / or a miscible agent, such as a dimethyl ether or carbon dioxide composition, can be used to increase the oil flow and / or gas from the reservoir.

The release of at least a portion of the water flooding mixture and / or other liquids and / or gases may be carried out using any known method. One suitable method is to inject the water-flooding mixture into a separate passage in a separate well, allowing the water-flooding mixture to be absorbed and then pumping out at least a portion of the water-flooding mixture along with gas and / or liquids. Another suitable method is to inject the water-flooding mixture into the first well and pumping out at least a portion of the water-flooding mixture together with gas and / or liquids through the 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 waterflooding mixture and / or other fluids and / or gases can be injected into the formation under some pressure up to the fracturing pressure of the formation.

In some embodiments, the waterflooding mixture may be mixed with oil and / or gas in the formation to form a mixture that may be produced from the well. In some embodiments, some waterflooding may be injected into the well, followed by another component to pump the composition through the formation. For example, air, liquid or vapor water, carbon dioxide, other gases, other liquids and / or mixtures thereof can be used to pump the flooding mixture through the formation.

In some embodiments, the waterflood mixture may be heated before it is injected into the formation to lower the viscosity of the fluids in the formation, for example, heavy oils, paraffins, asphaltenes, and the like.

In some embodiments, the waterflooding mixture may be heated and / or boiled while it is in the formation using a heated fluid or heater to lower the viscosity of the fluids in the formation. In some embodiments, implementation, you can use heated water and / or steam to heat and / or evaporate the mixture for flooding in the reservoir.

In some embodiments, the waterflooding mixture may be heated and / or boiled when it is inside the formation using a heater. One usable heater is described in the simultaneously pending United States Patent Application, filed 10/693816, filed October 24, 2003, and with the patent attorney folder number TH2557. United States Patent Application No. 10/693816 is hereby incorporated by reference in its entirety.

Figa and 3b:

Turning now to FIGS. 3a and 3b, a system 300 is illustrated in some embodiments of the present invention. System 300 includes an underground formation 302, an underground formation 304, an underground formation 306, and an underground formation 308. Equipment 310 is provided on the surface. Well 312 passes through formations 302 and 304 and has openings in formation 306. Parts 314 of formation 306 may, if necessary, have cracks and / or be perforated. During the initial production, oil and gas from the formation 306 is produced in parts 314, in the well 312, and it passes into the equipment 310. Then, the equipment 310 separates the gas that is sent to the gas processing 316 and the liquid that is sent to the liquid storage 318. Equipment 310 also includes a waterfloor mixture storage 330. 3a, the waterflooding mixture can be pumped into the depth of the well 312, as shown by the down arrow, and pumped into the reservoir 306. The waterflooding mixture can be left to soak in the formation for a period of time from about 1 hour to about 15 days, for example from about 5 to about 50 hours.

After an absorption period, as shown in FIG. 3b, the waterflooding mixture and oil and / or gas are then recovered from the well 312 to equipment 310. The equipment 310 is adapted to separate and / or recycle the waterflooding mixture, for example, by separation under the action of gravity, centrifugal separation, chemical absorption and / or by boiling the composition, condensing it, or filtering it, or chemically interacting and then storing or transporting the desired liquids and gases and re-injecting and / or releasing Single undesirable liquids and gases, for example by repeating the soaking cycle shown in Figures 3a and 3b, from about 2 to about 5 times.

In some embodiments, the waterflood mixture may be injected into the formation 306 at a pressure lower than the fracture pressure, for example, at a pressure of 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 a well in group 202 of wells, and well 312, as shown in FIG. 3b, producing from formation 306 may be a well in a group of 204 wells.

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

Fig. 3c:

Referring now to FIG. 3c, in some embodiments of the present invention, a system 400 is illustrated. System 400 includes an underground formation 402, formation 404, formation 406, and formation 408. Mining equipment 410 is provided on the surface. Well 412 passes through formations 402 and 404 and has openings in formation 406. Portions of formation 414 may, if necessary, have cracks and / or be perforated. When oil and gas are produced from the formation 406, they enter part 414 and go up the well 412 to the production equipment 410. Gas and liquid can be separated, and gas can be directed to the gas storage 416, and the liquid can be directed to the liquid storage 418. Mining equipment 410 is capable of producing and separating a waterflooding mixture that can be produced and stored in receiving / storage equipment 430. A waterflooding mixture is pumped into the lower part of well 432, in part 434 of formation 406. The waterflooding mixture passes through formation 406 to facilitate oil and gas production, and then the water-flooding mixture, oil and / or gas can be recovered through the borehole 412 using production equipment 410. The water-flooding mixture may then be recycled, for example, by separating the mixture for wind-up Nia from the rest of the production flow, and then re-injecting the composition into the well 432.

In some embodiments, a certain amount of waterflooding mixture or waterflooding mixture mixed with other components may be injected into well 432, after which another component pumps the waterflooding mixture or waterflooding mixture mixed with other components through formation 406, such as a fluid such as water in gaseous or liquid form; water mixed with one or more salts, polymers and / or surfactants; or gas, such as air; carbon dioxide; other gases; other liquids and / or mixtures thereof.

In some embodiments, a well 412 that produces oil and / or gas is a well in a group of 202 wells, and a well 432 that is used to inject the water flooding mixture is a well in a group of 204 wells.

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

Figure 4:

Turning now to FIG. 4, in some embodiments of the present invention, method 500 is illustrated. Method 500 includes injecting a water-flooding mixture shown as a checkerboard pattern in this figure; injecting an immiscible composition to enhance oil recovery shown by the diagonal structure in the figure; and oil and / or gas production from the formation, shown as a white structure in the figure.

An injection and production timeline for a group of 202 wells is shown using an upper timeline, while an injection and production timeline for a group of 202 wells is shown using a lower timeline.

In some embodiments, at time 520, the waterflood mixture is injected into group 202 of the wells for a period of 502 times, while oil and / or gas is produced from group of 204 wells for a period of 503 times. The waterflooding mixture is then injected into a group of 204 wells over a period of 505 times, while oil and / or gas is produced from a group of 202 wells over a period of 504 times. This injection / production cycling for well groups 202 and 204 may continue 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 front edge of the cavity can be filled with a water-flooding mixture, which is then pumped through the formation together with an immiscible composition for enhanced oil recovery. The waterflooding mixture can be injected into a group of 202 wells over a period of 506 times, then the immiscible oil recovery composition can be injected into a group of 202 wells over a period of 508 times, while oil and / or gas can be produced from a group of 204 wells during period 507 time. Then, the waterflooding mixture can be injected into the group of 204 wells for a period of 509 times, then the immiscible oil recovery composition can be injected into the group of 204 wells for a period of 511 times, while oil and / or gas can be produced from the group of 202 wells in over a period of 510 time. This injection / production cycling for a group of 202 and 204 wells may continue for a number of cycles, for example from about 5 to about 25 cycles.

In some embodiments, at time 540, there may be significant hydraulic communication between the well group 202 and the well group 204. The waterflooding mixture may be injected into group 202 wells for a period of 512 times, then the immiscible oil recovery composition may be injected into group 202 wells over a period of 514 times, while oil and / or gas may be produced from group 204 wells during period 515 time. The cycle of injection of miscible and immiscible compositions to enhance oil recovery in group 202 wells, while producing oil and / or gas from group 204 wells, can continue for as long as necessary, for example as long as oil and / or gas is produced from groups of 204 wells.

In some embodiments, the produced oil and / or gas may be transported to a refinery and / or to processing equipment. Oil and / or gas can be processed to produce commercial products, such as fuels for vehicles, such as gasoline and diesel, heating fuels, lubricants, chemicals and / or polymers. Processing may include distillation and / or fractional distillation of oil and / or gas to produce one or more distillation fractions. In some embodiments, the oil and / or gas and / or one or more distillation fractions may be exposed to one or more of the following methods: catalytic cracking, hydrocracking, hydroprocessing, coking, thermal cracking, distillation, reforming, polymerization, isomerization, alkylation mixing and dewaxing.

Waterflooding mixture

In some embodiments, oil and / or gas may be recovered from the formation using a waterflood mixture.

In some embodiments, a 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 about 90% to about 95%.

The choice of water used in the waterflooding mixture is not critical. The usable water to be used in the mixture may be salt water or fresh water, for example water obtained from a body of water, such as a sea, ocean, lake or river, water from a water well, buried water extracted from an underground formation , drinking water from an urban source of water, wastewater from an urban factory for the processing of organic waste or from another source of water. In some embodiments, the water used in the waterflooding mixture may be subjected to one or more stages of processing, such as those described in the publication of the patent application of the United States of America, number US 2009/0308609, which is incorporated herein as references in its entirety, for example, if water with a high salt content is used.

The waterflooding mixture may contain one or more additives to increase its effectiveness, for example, by increasing the oil recovery coefficient, by increasing the oil volume when saturated with gas, by lowering the viscosity of the oil, by increasing the mobility of the oil and / or by increasing the underground pressure in the reservoir.

In some embodiments, the waterflooding mixture may contain 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 to full miscibility 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 about, greater than 3.

In some embodiments, suitable waterflood additives are listed in the attached table 1.

In some embodiments, suitable waterflood mixture additives include alcohols, amines, pyridines, ethers, carbolic acids, aldehydes, ketones, phosphates, quinones, and mixtures thereof, wherein 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 waterflood 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 actually completely miscible in water, but which are not suitable as an additive to a water flooding mixture due to their very low separation coefficient. When working, it would be easy to mix these chemicals with water and pump them into an underground formation, but only a small amount of this chemical would then be transferred to crude oil. In practice, one of these chemicals with high solubility and low separation coefficient would only slightly increase the oil recovery coefficient compared to water flooding itself.

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

tetraethylene pentamine

triaethylenetetramine

sorbitol

diaethylenetriamine

ethylenediamine

tetraethylene glycol

triaethylene glycol

glycerol

formamide

diaethylene glycol

diethanolamine

ethylene glycol

monoethanolamine

pyruvic acid.

There are also a number of chemicals that have a high separation coefficient, but which are not suitable as an additive to the mixture for flooding due to their very low solubility in water. During operation, only a very small amount of these chemicals could be mixed with water and injected into the subterranean formation, so that only a small amount of the chemical would be transferred to crude oil. To obtain a large quantity of a chemical carried in crude oil, a very large volume of water would have to be injected. In practice, one of these chemicals with low solubility and a high separation coefficient would only slightly increase the oil recovery coefficient compared to water flooding itself.

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

n-hexadecane

n-pentadecane

n-heptadecane

n-eicosan

n-nonadecane

n-octadecane

n-tridecane

n-tetradecane

hexachlorobenzene

1-hexadecene

n-dodecan

1-pentadecene

1-tetradecene

1-heptadecanol.

Immiscible agents for oil production using enhanced oil recovery methods:

In some embodiments, suitable immiscible oil production agents using enhanced oil recovery methods include liquids or gases, such as gaseous or liquid water, air, nitrogen, mixtures of two or more of them, or other immiscible oil production agents with application of enhanced oil recovery methods, as is known in the art. In some embodiments, usable immiscible oil recovery agents using enhanced oil recovery methods are not miscible upon first contact or miscible upon repeated contact with oil in the formation.

In some embodiments, suitable immiscible oil recovery agents using enhanced oil recovery methods include water. The choice of water used as an immiscible agent is not critical. The usable water to be used may be salt water or fresh water, for example water obtained from a body of water, such as a sea, ocean, lake or river, water from a water well, buried water extracted from an underground formation, and potable water from an urban water source; wastewater from an urban organic waste processing factory or other water source. In some embodiments, the water used as the immiscible agent may be subjected to one or more processing steps, such as those described in the publication of the patent application of the United States of America, number US 2009/0308609, which is incorporated herein as references in its entirety, for example, if water with a high salt content is used.

In some embodiments, immiscible agents and / or waterflooding mixtures injected into the formation can 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 certain amount of oil in the reservoir that has absorbed a certain amount of additives to the water flooding mixture. Oil is stationary and cannot be recovered. To extract additives to the waterflooding mixture, some water without any additives is injected into the reservoir and brought into contact with oil, this water will absorb additives, and then the mixture of additives and water will be removed to the surface.

In some embodiments, the oil, as it is present in the formation before injecting any oil recovery agents using enhanced oil recovery methods, 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, the oil, as present in the formation before injecting any oil recovery agent using enhanced oil recovery methods, 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 methods:

In some embodiments, oil and / or gas may be produced from the formation using a waterflood mixture. To separate the produced fluids, liquids can be separated from the gases, for example, using separators based on gravity and / or centrifugal force, as is known in the art. Liquids can then be separated, while water can be separated from oil, for example, using separators based on gravity and / or centrifugal force, as is known in the art. Gas, oil, and water may still contain some additives to the flooding mixture. The oil may be subjected to a stripping process to quickly separate the additives to the waterflooding mixture and light hydrocarbons. This mixture of waterflood additives and light hydrocarbons may be added to the gas phase. The gas phase is then brought into contact with water, which preferably extracts additives to the water flooding mixture and leaves light hydrocarbons. At the end of the process, most of the additives to the waterflooding mixture are removed from oil and gas so that they can be discharged, while the water mixed with the additives to the waterflooding mixture will be easily recycled to the same field or stored and used in another mine.

Illustrative options for implementation:

In one embodiment of the present invention, a system for producing oil and / or gas from an underground formation is described, comprising: a well above the formation; a mechanism for injecting into the formation compositions for enhanced oil recovery, a composition for enhanced oil recovery, which contains water and an additive; and a mechanism for producing oil and / or gas from the formation. In some embodiments, the system also includes a second well at a distance from the first well, with a mechanism for producing oil and / or gas from the formation located in the second well. In some embodiments, an injection mechanism is located in the well, while a mechanism for producing oil and / or gas from the formation is in the well. In some embodiments, the subterranean formation is under a body of water. In some embodiments, the system also includes a mechanism for injecting an immiscible composition to enhance oil recovery into the formation after water and additives are released into the formation. In some embodiments, the implementation, the additive contains a chemical substance having a solubility in water of at least 1% (under atmospheric conditions) and an octanol-water partition coefficient of at least 1 (under atmospheric conditions). In some embodiments, the system also includes an immiscible oil recovery composition selected from the group consisting of water in gaseous or liquid form and mixtures thereof. In some embodiments, a wellbore comprises a wellbore arrangement comprising from 5 to 500 wells. In some embodiments, a mechanism for producing oil and / or gas from the formation is in the well. In some embodiments, the implementation, the additive contains a chemical substance having a solubility in water of at least 2% at a pressure of 50 bar and at a temperature of 25 ° C. In some embodiments, the implementation, the additive contains a chemical substance having a separation coefficient of crude oil - water, at least 2 at a pressure of 50 bar and at a temperature of 25 ° C.

In one embodiment of the present invention, a method for producing oil and / or gas, comprising injecting water and additives into the formation from the first well and producing oil and / or gas from the formation from the second well, is described. In some embodiments, the implementation, the mixture of water and additives contains from about 50% to about 99% water (molar). In some embodiments, the water and the additive are pumped at a pressure of 0 to 37,000 kilopascals higher than the initial pressure of the tank, measured before the injection begins. In some embodiments, the method also includes converting at least a portion of the produced oil and / or gas into a material selected from the group consisting of fuels for vehicles, such as gasoline and diesel, heating fuels, lubricants, chemicals and / or polymers. In some embodiments, the subterranean formation contains oil having a density in API degrees of 10 to 100. In some embodiments, the water further comprises a water-soluble polymer, providing an increase in viscosity of the mixture. In some embodiments, implementation, the method also includes reducing the pressure of saturation of oil in the reservoir using additives. In some embodiments, implementation, the method also includes increasing the coefficient of increase in oil volume when it is enriched with gas in the reservoir using additives. In some embodiments, implementation, the method also includes lowering the viscosity of the oil in the reservoir using additives. In some embodiments, water and an additive are injected into a reservoir having a temperature of at least 100 ° C, for example at least 250 ° C, measured before injection is started. In some embodiments, the subterranean formation has a permeability of from 0.0001 to 15 darcy, for example a permeability of from 0.001 to 1 darcy.

Those skilled in the art will recognize that many modifications and variations are possible in terms of the described embodiments of the present invention with respect to configurations, materials and methods, without deviating from their spirit and scope. Accordingly, the scope of the claims appended hereto and their functional equivalents should not be limited to the specific embodiments described and illustrated herein, since they are merely illustrative in nature.

Examples

Example 1 (Report 090130)

The full functionality of this unit is checked using three sets of core waterflooding experiments performed on Berea sandstone cores saturated with oil containing gaseous formation fluids, crude oil sample A, at 5600 psi. inch, 175 ° F. In the first flooding of the core, oil production is 43.8% using the first flooding, and 49.1%, increased oil production is obtained using the following water flooding 3.8 pore volume using 9.35% mol (percent molar) of the mixture for flooding dimethyl ether (OME) / water. In the second and third core flooding, the effect of the concentration of DME in water on the final oil production is investigated previously.

Specially designed for core diameters of 1-1.5 inches and 24 inches long, to minimize edge effects, the core waterflooding system can be used both horizontally and vertically with a maximum working pressure of 7500 psi. inch and at a maximum operating temperature of 300 ° F. The full functionality of this installation is checked using three sets of core flooding experiments:

No. 1. Water flooding followed by tertiary core flooding with 9.35% mole DME / water

No. 2. Secondary core flooding using 2% mole DME / water

Number 3. Secondary core flooding using 5% mole DME / water

These core flooding is performed on a Berea sandstone core saturated with oil containing gaseous formation fluids, crude A sample, vertically, under reservoir conditions (5600 psi, 175 ° F).

Preparation of oil containing gaseous formation fluids, crude oil sample A

Prepare oil containing gaseous reservoir fluids, a sample of crude oil A: it is first filtered and then combined with natural gas to obtain the desired GOR (gas / oil ratio) of 1435.6 cubic meters. pound / normal, oil. barrel (at 60 ° F) and at a gas saturation pressure of 5157 psi. inch. In principle, a sample of oil containing gaseous formation fluids in a transport vessel may undergo phase separation during transport. For this reason, the resulting cylinder for transporting oil containing gaseous formation fluids is mounted on a shaker and shaken at 175 ° F, 5600 psi. inch continuously for 48 hours to ensure the homogeneity of the oil sample containing gaseous reservoir fluids. At the end of the cylinder for transportation is installed in the system for flooding the core.

Preparation of a DME / Water Mixture

Ongoing experimental studies show that the solubility of DME in water is approximately 18% mol at 100: 11 ° C (212: 20 ° F) and 5600 psi. inch [6]. The result shows that in the first experiment, 10% mol of DME in saline can be used.

The brine filtered on a nanofilter, 30950 ppm, is used to prepare a DME / water mixture. For the preparation of 10% mol mixture of DME / water, 142 cubic meters. cm saline is mixed with 57.5 cubic meters. cm DME at 1000 psi inch at room temperature. In this case, a 9.35% mol DME / water mixture is actually prepared in a transport vessel, and the mixture is maintained at 5600 psi. inch throughout life to prevent phase separation. In the second and third core flooding, in order to study the effect of DME concentration in water on the final oil recovery, a 2% mol DME / water mixture is prepared by mixing 9.7 cubic meters. see DME with 120 cc cm saline and synthesize a mixture of 5% mol of DME / water by mixing 25 cubic meters. see DME with 120 cc see saline using the same method.

Core flooding device

A complete core flooding system is being built to study enhanced oil recovery under real reservoir conditions. The main components of the system are listed below:

1. One cell for core flooding. The cell is wrapped with an insulating ceramic fiber, and it can be heated using a silicone heater in the upper, middle and lower sections. The heat transfer fluid is water. This cell can be rotated for both vertical and horizontal flooding.

2. Three Isco Series D pumps. These Isco pumps have a capacity of 100 cc. cm and an upper pressure limit of 10,000 psi. inch, they are used to control effective pressure, discharge pressure and to maintain back pressure, respectively.

3. Three containers for transportation. The input containers for transportation are filled with fluids for injection into the core. Here, the injected substances can be either oil containing gaseous formation fluids, or saline, or a DME / saline mixture, in our case. The core flooding cell output is connected to a Temco 10,000 psi back pressure regulator (BPR). inch, and to maintain the back pressure using a container for transportation filled with gaseous argon.

4. Device for collecting effluent. A step-controlled valve device (VICI EMNMA-CE) is installed to collect effluents in test tubes. The output is switched to another test tube automatically after injecting 0.1 pore volume of the saline solution or DME / saline mixture. The resulting gas is released from the fluid and is collected in bags for sampling gas. In total, 20 fluid samples and 20 gas samples can be collected in one cycle.

5. Computer-controlled data processing system. It is used to track and control experiments and to record data files, including pressure, volume and temperature, and the like.

Core flooding procedure

Here, the authors select a core from sandstone Berea, saturated with crude oil, a sample of crude oil A (porosity 18%, permeability 100 milidarsi), for core flooding experiments to prove the concept. As discussed, in this study, three core flooding (No. 1-3) is carried out vertically. These core flooding are:

No. 1. Water flooding followed by tertiary core flooding with 9.35% mole DME / water

No. 2. Secondary core flooding using 2% mole DME / water

Number 3. Secondary core flooding using 5% mole DME / water

The sequence that is followed during core experiments is described below:

1. Berea sandstone cores with a diameter of 1 inch and a length of 24 inches are cleaned by washing with chloroform to remove any hydrocarbons, then washed with methanol to remove any salts present. Then, the solvent in the core core is removed by drying the core in an oven at 100 ° C. for 24 hours. The mass of dried pure cores is measured.

2. Then the core is placed in a sleeve using a Teflon heat-shrink tubing and loaded into a desaturation cell to be saturated with saline to determine pore volume (PV). The temperature of the desaturation cell is first set at 75 ° F and an overpressure of 1150 psi is applied. inch. Then the core is evacuated, and then a sample of crude oil A (116.382 ppm) is saturated with a synthetic salt solution of the formation. In laboratory conditions, only divalent and multivalent salts are chosen for the preparation of synthetic saline. Salts are bought from Sigma-Aldrich Co. The brine is filtered through a 0.2-micron filter made of polytetrafluoroethylene (PTFE) and degassed before use. The exact pore volume is measured during the brine saturation process.

3. Subsequently, the saline solution in the core core is displaced by degassed crude oil, crude oil sample A, until the initial conditions for oil saturation are reached using a ceramic bar of 15 bar. This stage is carried out at a maximum speed of 1 cc. cm / hr at a discharge pressure of 175 psi inch applied to experiments No. 1 and No. 3, and at a discharge pressure of 150 psi. inch applied to experiment No. 2, back pressure of 25 psi an inch is applied in all of these experiments. The choice of injection rate is based on the total pore volume, and it is kept low to allow completion of flow experiments within a reasonable time. The method is carried out until the visible increase in the volume of hydrocarbons in the pores ceases. During this process, the exact volume of hydrocarbons in the pores and the irreducible saturation of water can be measured. After pumping, the temperature is raised to 175 ° F. A core saturated with degassed crude oil is aged for 4 weeks to achieve a reproduced initial state.

4. After that, cores saturated with degassed crude oil are transferred to a core flooding cell. Before the transfer, cores saturated with degassed crude oil are additionally wrapped with Teflon tape and then with aluminum foil. Cylinders at the edges are designed with grooves in the form of o-rings. Then, both pistons and cores wrapped in aluminum foil are packaged with a thick shrink Teflon tube. The forces exerted on the o-rings from the heat shrink tubing provide sealing edges.

5. Then, the degassed crude oil in the core core is displaced by 2 pore volumes of synthetic oil containing gaseous formation fluids, crude oil sample A, at a flow rate of 1 cubic meter. cm / hour. During this process, the temperature of the core flooding cell and oil cylinder containing gaseous formation fluids is set at 175 ° F. The effective pressure is set at 6,600 psi. inch with pore pressure set at 5600 psi inch, this gives an effective voltage of 1000 psi. inch. Effluents pass through a BPR and a device controlled by a multi-position actuator, and finally they are collected in test tubes.

6. After the displacement of crude oil containing gaseous reservoir fluids, the inlet is connected to a transport tank filled with working agents for flooding the core (water or a mixture of DME / water). Core flooding is carried out at a flow rate of 1 cubic meter. cm / hour. The resulting fluids are collected in test tubes. Most of the gas is released from the resulting fluids under ambient conditions, then it is collected in sample bags to analyze the composition, to understand the extraction process. As discussed above, a total of 20 liquid samples and 20 gas samples are collected in one cycle.

7. After the core flooding is completed, the pressure in the pores is reduced to environmental conditions, while part of the residual oil goes outside and is collected. Then the core core is baked in an oven at 100 ° C for 24 hours to obtain the mass of the remaining oil. The addition of the volume of oil that has come out and the volume of the remaining oil gives an irreducible volume of oil.

Final oil recovery factor

The experiments are generally regulated and monitored by a computer. Pressure, volume, flow rate and temperature are recorded every 1 minute. The mass balance is calculated after the end of the experiment. As previously described, most of the residual oil in the core core is exposed. The core core is then transferred to an oven and dried at 100 ° C. for 24 hours to measure the amount of oil remaining. The table is a summary at the end of the core flooding, the mass balance is approximately 100% of the oil mass balance at each stage that is carried out. In experiment No. 1, a total of approximately 92.9% of the oil recovery during the primary flooding and the subsequent subsequent flooding with 9.35% mol of DME / water is achieved.

No visible residual oil was observed from the core depth after tertiary core flooding with 9.35% mol of DME / water. In experiment No. 2 and No. 3 receive the final oil recovery of 52.5% and 71.5%, respectively.

Since the effluents are collected in test tubes, while gas samples are separated as the gas phase from the liquid phase and collected in bags for gas samples, the oil recovery coefficients at each stage are calculated as a function of the volume of injected hydrocarbons in the pores. The graph shows the oil recovery coefficient curves obtained by the GOR and the DME concentration in the produced gas as a function of the volume of injected hydrocarbons in the pores from experiment No. 1. Water flooding yields approximately 43.8% of oil production (secondary recovery) and water breakthrough after injection of a saline solution of about 0.46 of the volume of hydrocarbons in the pores is observed. After injecting 1.1 volumes of hydrocarbons in the pores, the inlet is switched to a cylinder with a mixture of 9.35% mol of DME / water, and flooding with 9.35% mol of DME / water ultimately gives an increase in oil production of 49.1% s by injecting 5 volumes of hydrocarbons in the pores (tertiary recovery). During tertiary flooding, the collected gases after injection of 1.50, 2.31, 2.85, 4.21, 5.31 and 5.90 volumes of hydrocarbons in the pores are selected for analysis by gas chromatography (GC). GC analysis shows that the greater the injection of DME / water, the higher the concentration of DME in the produced gas, which is consistent with the obtained GOR data.

Core Flood Experiment Summary

Parameter Core flooding No. 1 Core flooding No. 2 Core flooding No. 3 Pore Volume (cc) 51.35 51.37 53.04 The volume of hydrocarbons in the pores (cubic cm) 38.69 33.27 38.62 Formation Volume Factor (FVF) 1,56 1.44 1,50 Initial oil saturation (%) 75.35 64.8 72.8 Minimum water saturation (%) 24.65 35,2 27,2 The volume of outgoing degassed crude oil (cubic cm) 0.75 6.7 5 The remaining volume of degassed crude oil (cubic cm) 1.23 4.12 2,55 Recoverable volume of degassed crude oil (cc) 23.04 12.14 18,4 Final oil recovery 92.9% 52.5% 71.5%

7 shows the results for water flooding with 9.35% mol of DME / water, where recovery by the first water flooding reaches a plateau of about 45%, then additional recovery is achieved using 9.35% mol of the mixture for water flooding DME / water.

Additionally, experiments No. 2 and No. 3 are carried out to study the effect of the concentration of DME in water on the final oil recovery. The graph shows the production curve as a function of the volume of hydrocarbons pumped into the pore. Of course, DME / water flooding supports the production of crude oil even after a breakthrough. In essence, the more DME / water mixtures are injected and the higher the concentration of DME in water, the higher the final oil recovery. Finally, injection of 2.91 volumes of hydrocarbons in the pores of 2% mol of DME / water gives a final oil recovery of 52.5%. The injection of 2.5 volumes of hydrocarbons in the pores of 5% mol of DME / water gives a final oil recovery of 71.5%.

Fig. 8 shows the results for flooding with 2% mol of DME / water compared to the results of flooding with 5% mol of DME / water.

Example 2 (Report 020810)

Two experiments on waterflooding of long cores, carried out on cores from sandstone Berea, restored to their original state using crude oil, a sample of crude oil C (viscosity 65 cP). Both experiments use DME-enhanced flooding in tertiary mode. The concentration of DME in the injection stream is 9.35% mol. Experiment No. 1 is a continuous injection of 7 PV of a DME / water mixture after initial flooding, and after flooding enriched with DME, the authors switch back to flooding with pure water. During the whole process, 92% oil recovery is generally achieved. In comparison, only 1 PV of the DME / water mixture is injected after normal water flooding in experiment No. 2. During injection under pressure, DME / water reaches a 28% increase in production.

crude oil sample A crude oil sample B crude oil sample C Saturation Pressure [psi] inch] 5188 3538 1071 Molecular Weight [kg / kmol] 97.2 145.54 287.58 ρ [kg / m ³ ] 731.1 840.4 865 µ [cP] at saturation 0.543 5,744 65 Tank Temperature [° F] 175 135 115 Tank Pressure [psi] inch] 5500 3500 1350 The ratio of gas: oil [cubic cm / cu cm] 251.33 91.84 23

Two core flooding is carried out on cores with a permeability of 100 millidarsi from Berea sandstone, initialized using crude oil, a sample of crude oil C, and synthetic saline. They are:

No. 1 Water flooding followed by water flooding with 7 PV 9.35% mole DME / water, followed by flooding.

No. 2 Water flooding followed by flooding with 1 PV of 9.35% mole DME / water, followed by flooding.

For both experiments, initial waterflood can typically give 45% OOIP.

For experiment No. 1, after water flooding, the authors continue to inject the DME / water mixture until the production curve reaches saturation. During this period, a 45% increase in oil production is achieved. Further flooding after flooding with DME / water gives a small amount of oil, very slowly (2%), which does not have much effect on the final recovery of oil.

For experiment No. 2, only 1 PV of DME / water mixture is injected after normal flooding. A 28% increase in production is achieved during injection under pressure of DME / water and then subsequent flooding with clean water. 11% of them are obtained after switching back to flooding with pure water, which is used to force the DME mass through the core.

In addition to this, a comparison of experiments and simulations shows that the main aspects of the extraction method are clear and can be modeled accordingly.

An oil containing gaseous formation fluids, a crude oil sample C is prepared. A degassed crude oil, a crude oil sample C, is first filtered and then combined with natural gas to obtain the desired GOR of 140.65 st. cube ft / normal, oil barrel (at 60 ° F). The saturation pressure of the synthesized oil containing gaseous formation fluids is 1071 psi. inch atm Since phase separation may occur in a sample of oil containing gaseous formation fluids during transport, some combination procedure, as described above, is followed to ensure the homogeneity of the sample of oil containing gaseous formation fluids before being transferred to the cylinder for oil containing gaseous formation fluids vibes; in a core flooding installation. A PVT (pressure-volume-temperature) study of the combined oil containing gaseous formation fluids, a sample of crude oil C, shows that its viscosity at a saturation pressure of 65 cP.

Preparation of the core returned to its original state

Cores from Berea sandstone returned to its original state (1 inch diameter and 24 inches long) are prepared using a 15 bar porous plate. Cores first saturate 116381 ppm. synthesized saline at an effective pressure of 1000 psi. inch. After that, the brine is displaced by degassed crude oil, a sample of crude oil C, until the water is saturated at a minimum capillary pressure of 150 psi. inch. Then the cores are aged at 115 ° F under pressure for 28 days to achieve the initial state.

Preparation of a DME / Water Mixture

The brine filtered on a nanofilter, 30950 ppm, is used to prepare a DME / water mixture. For the preparation of 9.35% mol of a mixture of DME / water 141.1 cubic meters. cm saline is mixed with 58.9 cubic meters. cm DME at 1350 psi inch and at room temperature in a shipping container.

A core flooding unit is also described in detail in a previous report, and the system is designed for a maximum operating pressure of 7500 psi. inch and maximum operating temperature of 300 ° F. In these studies, the authors set the pressure in the pores at 1350 psi. inch (reservoir pressure above saturation pressure) and effective pressure at 1000 psi. inch. The temperature of both the core holder and the cylinder for oil containing gaseous formation fluids is maintained at 115 ° F (reservoir temperature).

After loading into the core holder, the degassed crude oil in the core core is displaced with oil containing gaseous formation fluids, crude oil sample C, at a flow rate of 0.018 cubic meters. cm / min under reservoir conditions. During this process, the effluent is collected in a graduated cylinder using a Temco back pressure regulator.

The pressure difference between the inlet and outlet of the core is constantly increasing until the breakthrough, the system reaches equilibrium after injection of about 1 PV of oil containing gaseous formation fluids. P increases slightly after 50 hours of injection, which may be caused by temperature fluctuations.

The experiments are generally controlled and monitored by computer. Pressure, volume, flow rate and temperature are recorded every minute. The mass balance is calculated after the end of the experiment. Previous results for oil containing gaseous formation fluids, crude oil sample A, show that most of the residual oil in the core core may come out. The reservoir factor for oil containing gaseous reservoir fluids, a sample of crude oil C, (1.08) is much smaller than the reservoir factor for oil containing gaseous reservoir fluids, a sample of crude oil A, (1.66). For this reason, no oil has escaped during these two experiments. Then the core core is transferred to the oven and dried at 100 ° C to measure the remaining oil.

Core Flood Experiment Summary

Parameter Core flooding No. 1 Core flooding No. 2 Pore Volume (cc) 53.04 51.35 The volume of hydrocarbons in the pores (cubic cm) 41.57 38.18 Formation Volume Factor (FVF) 1.06 1.06 Initial saturation with water (%) 78.37 74.35 Minimum water saturation (%) 21.63 25.65 The volume of outgoing degassed crude oil (cubic cm) 0 0 The remaining volume of degassed crude oil (cubic cm) 4.64 10.90 Recoverable volume of degassed crude oil (cc) 36.35 25,99 Final oil recovery 92% 73%

The mass balance should be close to 100%. In fact, in the end, the mass balance is close to 100%, but slightly exceeds this value, since at each stage the mass balance is carried out for oil, especially for experiment No. 1. The apparent formation of an emulsion in some effluents is expected to be the main reason for this slight revaluation.

In experiment No. 1, during the initial waterflooding, 45% oil production is achieved, followed by water flooding with 9.35% mole DME / water can give an additional 45% increase in oil production. The subsequent water flooding gives some additional oil, very slowly (2%), which does not have much effect on the final oil recovery.

In experiment No. 2, the initial waterflood clearly provides oil production of 45%. To study the sensitivity to the size of the injected mass, only 1 PV is subsequently injected with 9.35% of the DME / water mixture, a 28% increase in production is achieved during injection under pressure of DME / water and the subsequent waterflood with pure water. 11% of them are obtained after switching back to flooding with pure water, which is used to force the DME mass through the core.

Experiment No. 1 with continuous injection

Since the effluents are collected in test tubes, while the gaseous samples separated from the liquid phase are collected as separate phases in the bags for gaseous samples, the oil recovery coefficients for each stage are calculated as a function of the injected volume of hydrocarbons in the pores.

Initially, typical flooding behavior may be observed. After the initial oil recovery, some additional drainage of the formation follows after water breakthrough. Water flooding yields approximately 45% oil recovery (secondary oil recovery) and water breakthrough is observed after about 0.4 volumes of hydrocarbons are injected into the pores of the saline solution. For a rather viscous oil, similar to a sample of crude oil C, it is not unexpected that a significant amount of oil is produced after water breakthrough during additional drainage of the reservoir.

After injection of 4.2 volumes of hydrocarbons in the pores, the inlet is switched to a cylinder with a mixture of 9.35% mol of DME / water, and this stage ultimately gives a 45% increase in oil recovery after injection of 9 volumes of hydrocarbons in the pores (tertiary oil recovery) .

During tertiary water flooding, the collected gases after injection of 4.74, 6.33, 5.91, 7.60, 8.39 and 10.71 volumes of hydrocarbons in the pores are selected for analysis by gas chromatography (GC). GC analysis shows that the greater the injection of DME / water, the higher the concentration of DME in the produced gas, which is consistent with the data obtained for GOR.

After the authors switch back to pure water flooding, GIWR decreases very quickly, and additional flooding does not have a big impact on improving oil recovery.

Experiment No. 2 with injection under pressure

The pressure injection method will limit the total amount of DME used. The pressure injection experiment shows a behavior similar to experiment No. 1 before switching back to flooding with clean water. Initial waterflooding clearly gives an oil recovery of 45%. Tertiary injection under pressure (1 PV) and subsequent flooding with clean water gives a 28% increase in oil recovery. 11% of them are obtained after switching back to flooding with pure water, which is used to force the DME piston through the core.

Oil production is resumed after about 0.4 PV of the DME / water mixture is injected. This is also consistent with the observation in experiment No. 1. The critical finding here is that additional water flooding can extract an additional 11% OOIP.

After the initial pressure drop, the curve equalizes when the flow reaches a steady state. The initial pressure drop is caused by the fact that the viscous pressure drop is much lower than the initial viscous pressure drop needed to move the oil, a sample of crude oil C, through the core. The pressure drop during additional reservoir drainage is controlled by both viscous and capillary pressure. Despite the fact that for a viscous oil similar to a sample of crude oil C, capillary forces are less significant than for lighter oils, they cannot be completely neglected. After the authors switch to flooding using 9.35% mol of DME / water, P increases when DME begins to diffuse from the aqueous phase to the oil phase, while this residual oil is enriched in gas and the saturation of the oil increases. This reduces the mobility of the water and increases the mobility of the oil.

Claims (10)

1. The method of oil and / or gas production, including:
injecting water and additives into the formation from the first well and
the production of oil and / or gas from the reservoir from the second well,
wherein said water and the additive are a mixture containing from about 50 to 99 mol% of water and an additive containing dimethyl ether, diethyl ether or methyl ethyl ether,
moreover, groups of wells are used, one group is used for waterflooding and another for oil production during the first period of time, then groups of wells for waterflooding and production are switched during the second period of time, a cycle is made up of the first and second time periods, each cycle increase in time by 5-10% of the duration of the previous cycle, in the first 10-80% of the duration of the cycle, one mixture for flooding with additives is pumped, and the rest of the cycle time, another mixture for flooding is pumped I am with additives, including immiscible ones. 2. The method according to p. 1, in which water and the additive are pumped at a pressure exceeding from 0 to 37,000 kilopascals the initial pressure of the reservoir, measured before the start of injection. 3. The method according to claim 1 or 2, further comprising converting at least a portion of the produced oil and / or gas into a material selected from the group consisting of fuels for vehicles, such as gasoline and diesel fuel, fuel for heating purposes , lubricants, chemicals and / or polymers. 4. The method of claim 1 or 2, wherein the subterranean formation contains oil having an API index of 10 to 100. 5. The method according to p. 1 or 2, in which the water further comprises a water-soluble polymer, which allows to increase the viscosity of the mixture. 6. The method according to p. 1 or 2, further comprising lowering the saturation pressure of oil in the reservoir using additives. 7. The method according to p. 1 or 2, further comprising increasing the coefficient of gas enrichment of oil in the reservoir using additives. 8. The method according to p. 1 or 2, further comprising reducing the viscosity of the oil in the reservoir using additives. 9. The method according to p. 1 or 2, in which water and the additive is injected into the reservoir having a temperature of at least 100 ° C, for example at least 250 ° C, measured before injection begins. 10. The method according to any one of paragraphs. 1 or 2, in which the subterranean formation has a permeability of from 0.0001 to 15 darcy, for example a permeability of from 0.001 to 1 darcy.

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