RU2597039C1 - Method of heavy oil deposit development - Google Patents

Abstract

FIELD: oil industry.

SUBSTANCE: invention relates to methods of oil deposits development, in particular, to methods of thermal impact on deposit, containing high-viscosity oil. Method of heavy oil deposit development, which involves drilling of flowing and injection wells and pumping methane-containing gas in formation, produced gas is pumped back in the formation after separation, before pumping produced gas in the formation catalytic conversion is performed to produce heated methane-containing gas, containing water vapour, carbon dioxide and hydrogen.

EFFECT: technical result is increasing oil recovery factor, reduced power resources consumption, reduced costs for pumping and losses, associated with excess heat release into atmosphere.

7 cl, 1 dwg, 6 tbl

Description

Technical field

The invention relates to the development of oil fields, in particular to methods of thermal exposure of a reservoir containing highly viscous oil.

State of the art

The prior art methods for increasing oil recovery in the development of deposits of heavy oils and bitumen by increasing the volume of production due to stable and continuous heat exposure, increasing the efficiency of obtaining a heated coolant, increasing the coverage of viscous oil or bitumen reserves by area and section, as well as by reduction of produced water and the share of condensate in the volume of selected products.

In particular, the Republic of Tatarstan has significant resources of super-viscous oils (over 1.4 billion tons), most of which are associated with deposits of the Ufa and Kazan layers of the Perm system. About 450 deposits have been identified, the bulk of which lies at a depth of 50-250 m.

Involvement in the development of resources of unconventional hydrocarbon accumulations is of particular relevance in connection with the planned exhaustion of more accessible traditional hydrocarbon resources. The main resources of “shale” oil are confined to the Bazhenov Formation of Western Siberia, the Domanik formation of the Volga-Ural Region and the Timan-Pechora Province. The total resources of “shale” oil, according to VNIGRI experts, are 36 billion tons. For the Bazhenov suite, estimates of light oil associated with anomalous zones are from 5 to 15 billion tons, and the total resource of “canned” unconventional oil is estimated from 70 to 170 billion tons. Specialists of IPG RAS have discovered and intensively studied “matrix” oil associated with carbonate complexes of rocks in the fields of the Caspian Depression. Unconventional oil and gas resources require the creation and use of new technologies for their development.

The large-scale development of unconventional resources in Russia and many other countries is hampered for various reasons, including the imperfection of the created technologies and environmental restrictions, in particular, when using steam-gravity technology, it is necessary to master the process control in real time based on the analysis of the dynamics of temperature distribution along trunk and mineralization of associated water, providing high flow rates in a wide range of heterogeneity of oil saturation of the reservoirs and optimization of steam long-term relationship, which will create conditions for increasing the thermal efficiency of the use of energy sources. The use of nuclear energy sources will reduce hydrocarbon consumption to a minimum, which will further increase the efficiency of the technology. When approaching the critical state of water (~ 370 ° C, 22 MPa), the heat of vaporization will tend to zero, which will not require any additional energy costs for the evaporation of water at any rate of its supply to oil reservoirs. Such parameters can provide atomic high-temperature energy sources.

The prior art method is known according to which pairs of horizontal injection and production wells are used. The horizontal sections of these wells are placed parallel to one another in the vertical plane of the reservoir. Wells are equipped with a tubing string, which allows simultaneous injection of heat transfer fluid and product selection, injection of heat transfer fluid, heating of the productive formation with the creation of a steam chamber, production selection through the production well and control of the technological parameters of the formation and well (see RF patent No. 2379494 for an invention , published on January 20, 2010).

The disadvantage of this method is the lack of efficiency of oil recovery, because when steam is injected and oil is taken from one well at the same time, quick steam breakouts occur, and during cyclic exposure, the steam is unproductive for re-heating the cooled reservoir during the selection period, i.e. high energy consumption.

The prior art method for the production of highly viscous oil through thermal exposure to the underlying oil reservoirs when they supply them with a working substance - water. Heated water is supplied through the pressure pipe to the oil layer at a pressure higher than the pressure in the oil layer and oil is extracted to the surface through the intake pipe. At the same time, water is supplied to the pressure pipe at a pressure and temperature that exclude the phase transition of water or the water mixture from liquid to steam in the pressure pipe, but are sufficient for this phase transition at the outlet of this pipe. The resulting steam is fed into the oil layer. The efficiency of the development of high-viscosity oil layers by more intensive heating due to the generation of water vapor with its subsequent injection directly in the area of the oil layers is increased (see RF patent No. 2375559 for the invention, publ. 10.12.2009).

The known method is limited by geological conditions under which a phase transition can occur. In addition, difficulties arise when working with a heated super-high pressure coolant and its production in heating devices.

The prior art method is known in which the production of viscous oil or bitumen from the reservoir is carried out by heating by pumping heat carrier and gas into it. According to the invention, a gas is a mixture of non-condensable gases generated during the combustion of liquid fuel, in the following ratio of components, weight. %: nitrogen 15.2-19.0, carbon dioxide 4.8-6.0. The gas content in the mixture with the coolant is 20-25 wt. % The mixture and steam are injected according to the quantity of injected steam according to the empirical formula. The invention allows for the intensification of the oil production process, to increase the efficiency of their extraction due to the combination of thermal and physico-chemical effects and to reduce the water content of the products (see RF patent No. 2223398 for the invention, publ. 07.05.2002).

The disadvantage of this method is the need to deliver liquid fuel for heating the coolant and gas, the need for compression of the products of combustion of hydrocarbons, which increases the cost of implementing the method.

Partially, these shortcomings were solved in a method that included the construction of an upper injection and a lower production well equipped with filters with openings located one above the other, the descent of technological pipe columns with pumps for the selection of heated super-viscous oil, heating the formation by pumping coolant into the injection well, and heating the cross-hole zone of the formation , reducing the viscosity of super-viscous oil, analysis of the state of the reservoir for uniform heating and the implementation of uniform heating of the reservoir, characterized in that the upper the injection and lower production wells are double-mouth with horizontal sections, and the filter of the horizontal section of the upper double-well injection is divided into two heating zones, inside the filter opposite each of the heating zones, shanks are installed that are plugged at the ends with holes that are lowered at the ends of the pipe process columns. The invention allows for the intensification of the oil production process, to increase the efficiency of their extraction due to thermal effects and to reduce the water cut of products (see RF patent No. 2527984 for the invention, published on 09/10/2014).

The known method is limited only by thermal exposure without contact of oil with a heated coolant, which reduces the possibility of physico-chemical effects.

A more effective method, including drilling production and injection wells and injecting methane-containing - associated petroleum or natural gas into the formation, characterized in that they implement a sequence of technological operations in alternating cycles, each of which includes three stages; at the first stage, gas is injected into the injection well during the time T1, during which the formation pressure is increased, liquid hydrocarbons are dissolved and released from the bound state in the kerogen-containing matrix; at the second stage, the injection and production wells after time T are idle for a period of time (T2-T1), during which the hydrocarbons continue to dissolve and the reservoir pressure is equalized, followed by further penetration of the gas into the low-permeability kerogen-containing matrix; at the third stage, production wells are put into operation for a period of time (T3-T2); after that, the process of injecting gas into the injection well again begins; the time T is taken to be about 1-3 months, the duration of the period (T2-T1) is established on the basis of field studies from the condition of maximizing the accumulated oil production by producing wells at time T2, and time T3 corresponds to the moment when the production rate of the oil well reaches a predetermined minimum value; the extracted and injected gases after separation are pumped back into the reservoir, which helps to reduce the supply of third-party gas (see RF patent No. 2513963 for the invention, publ. 04/20/2014 - prototype).

The disadvantage of this method is the limitation of the thermobaric and cracking effects on oil, which significantly reduces the mobility of the oil and the efficiency of its extraction.

Disclosure of invention

The technical result of the claimed invention is to reduce energy consumption, reduce pumping costs and losses associated with the release of excess heat into the atmosphere, increase the oil recovery coefficient.

The technical result is achieved by the fact that in the method of developing a heavy oil deposit, including drilling production and injection wells and injecting methane-containing gas into the formation, in which the produced gas after separation is pumped back into the formation, before the injection of produced gas into the formation, it is catalytically converted to produce heated methane-containing gas containing water vapor, carbon dioxide and hydrogen.

In a preferred embodiment:

- the conversion is carried out by supplying heated water vapor and thermal energy from an external energy source in which nuclear and / or organic fuel is burned;

- associated petroleum gas produced from a heavy oil reservoir is used as produced gas;

- feed water to produce water vapor is supplied from a reservoir replenished with condensate released from the produced gas;

- the temperature regime of conversion is supported by changing the flow rate and composition of the produced gas;

- the injection of methane-containing gas is accompanied or alternated with the injection of solvents, in the form of rims or by enrichment of the methane-containing gas with a solvent;

- methane-containing gas is injected periodically, supplying air and / or hydraulic fracturing fluid based on water containing condensate from the produced gas at intervals into the formation.

Brief Description of the Drawings

The features and essence of the claimed invention are explained in the following detailed description, illustrated by the drawing (Fig. 1), which shows the following.

The figure 1 shows a diagram of the implementation of a method for developing a heavy oil reservoir, where:

1 - layer;

2 - injection wells;

3 - methane-containing gas;

4 - producing wells;

5 - produced oil;

6 - separator;

7 - produced gas;

8 - condensate;

9 - grocery oil;

10 - mixer;

11 - gas-water mixture;

12 - heat exchanger;

13 - coolant;

14 - energy source;

15 - catalytic reactor;

16 - node supply of the injection agent.

The implementation of the invention and examples of implementation

An example implementation of the invention is the method of developing a heavy oil reservoir, described below.

In an example embodiment of the invention, the products of the catalytic conversion of the produced gas are used as heated methane-containing gas containing water vapor, carbon dioxide and hydrogen, which allows us to characterize the features of the invention as applied to the development of a heavy oil reservoir.

The method is as follows.

The formation 1 of the heavy oil deposit is heated by pumping methane-containing gas 3 containing water vapor, hydrogen and carbon dioxide (CO ₂ ) into it through injection wells 2. Produced oil 5 is extracted through production wells 4 from reservoir 1, which is sent to a separator 6, where produced gas 7 and condensate 8 are separated from produced oil 5, after which product oil 9 purified from water and gas is sent for shipment. The produced gas 7 and condensate 8 are fed into the mixer 10, from which the gas-water mixture 11 is sent to the heat exchanger 12, where, using the heat carrier 13 heated in the energy source 14, the gas-water mixture 11 is heated to a temperature of 600-700 ° C, and then fed to the catalytic reactor 15, where the adiabatic conversion reaction of the produced gas 7 is carried out to produce heated methane-containing gas 3, which is directed through injection wells 2 into formation 1 of a heavy oil deposit.

The injection of methane-containing gas 3 can be accompanied or alternated with the injection of solvents, in the form of rims or by enriching the methane-containing gas 3 with a solvent using the injection agent supply unit 16.

The methane-containing gas 3 can be injected periodically, supplying air and / or hydraulic fracturing fluid based on water containing condensate 8 released from the produced gas 7 at intervals into the reservoir 1 through injection wells 2.

The catalytic reactor 15 of the produced gas 7 can be located at a considerable distance and can supply many injection wells 2. The condensate 8 can be removed from the produced oil stream 5 or from the produced gas 7 in the separator 6 by condensation 8 or sorption followed by regenerative heating using heated methane-containing gas 3.

In the case of sorption, the technology of short-cycle heating or non-heating adsorption on coal or zeolite sorbents can be applied. Heated adsorption is preferable, allowing to obtain a higher pressure of the product (condensate 8 with dissolved carbon dioxide). Since the condensate 8 leaves the sorbent in the form of steam during desorption, steam is condensed (as in the case of condensation output), for example, by heating the inlet stream of the produced gas 7, which is supplied to the mixer 10, and then heated to the heat exchanger 12 and a catalytic reactor 15 filled with a catalyst, mainly based on Nickel.

Produced gas 7, the main component of which is methane, with a pressure above 2.0 MPa is piped to a mixer 10, in which the gas is saturated with circulating condensate 8, extracted from the produced gas 7. The resulting gas-water mixture 11 can be mixed with superheated steam, maintaining in the resulting vapor-gas the mixture, the volumetric content of water vapor in the range of approximately 4 to 8 times greater than the volumetric content of methane, and sent to the heat exchanger 12, in which the vapor-gas mixture is heated to a temperature in the range of 600 ° C-700 ° C and sent to a catalytic reactor 15 filled with a catalyst nozzle. The catalytic reactor 15 can be multi-stage, in each of which the reaction is similar. In the first stage of the catalytic reactor 15, a partial conversion of higher methane homologues (ethane, propane, butane, etc.) is carried out to a volume fraction of not more than 0.00001-0.00002% (by dry gas), after which a stream with a temperature of about 400 ° C is re-directed to a heat exchanger 12, in which the vapor-gas mixture is heated before the second stage of the catalytic reactor 15. The choice of heating temperature is determined by the need to avoid the formation of soot in the adiabatic reactor 15, which determines the preferred level of the upper possible temperature of 680 ° C. On the other hand, the equilibrium degree of methane conversion below 620 ° C, even at relatively high steam / gas ratios, becomes almost unacceptable. After exiting the second stage of the catalytic reactor 15, a stream with a methane content of about 30% (by dry gas) is sent to a heat exchanger 12, and then with a view to a deeper methane conversion, to a third stage of a catalytic reactor 15, after which the stream is sent to a superheater (in the figure not shown), in which the stream of water vapor produced from feed water is overheated, after which methane-containing gas 3 is directed through injection wells 2 into reservoir 1 of a heavy oil deposit. In the process, the volumetric content of methane in the methane-containing gas stream 3 is maintained at the outlet in the range of 33-48%, hydrogen - 35-44%, calculated on dry gas.

Below are the results of calculating the technology for methane-containing gas 3 in accordance with the above method.

The conversion of the produced gas 7 is carried out by supplying heated water vapor and thermal energy from an external energy source 14, in which nuclear and / or organic fuel is burned.

Associated petroleum gas produced from a heavy oil reservoir is used as produced gas.

Feed water to produce water vapor is supplied from a reservoir replenished with condensate 8 released from the produced gas.

The temperature regime of conversion in the reactor 15 is also supported by changing the flow rate and composition of the produced gas 7.

The calculation was carried out for a technology productivity of 1000 m ³ / h of methane-containing gas 3.

GAS INPUT 1st stage:

steam: gas = 4.000 V dry gas = 585.00 m ³ / h R = 30.00 ati T = 450.00 ° C

GAS OUTLET 1st stage:

steam: gas = 3.851383 V dry gas = 604.98 m ³ / h R = 29.95 ati T = 443.97 ° C

GAS INPUT 2nd stage:

steam: gas = 3.851 V dry gas = 604.98 m ³ / h R = 29.95 ati T = 645.00 ° C

GAS OUTLET 2nd stage:

steam: gas = 2.606130 V dry gas = 847.89 m ³ / h R = 29.88 ati T = 558.15 ° C

GAS INPUT 3rd stage:

steam: gas = 2.606 V dry gas = 847.89 m ³ / h R = 29.88 ati T = 645.00 ° C

GAS OUTLET 3rd stage:

steam: gas = 2.095394 V dry gas = 1015.71 m ³ / h R = 29.81 ati T = 583.65 ° C

Thus, as shown by calculations, from 585 m ³ / h of produced gas 7 in the specified method, 3144 m ³ / h of methane-containing gas 3 is produced, which is directed through injection wells 2 into formation 1 of a heavy oil deposit. At the same time, in the composition of methane-containing gas 3, 2,128 m ³ / h of water vapor, 473 m ³ / h of methane, 428 m ³ / h of hydrogen, 102 m ³ / h of carbon dioxide are fed into reservoir 1.

In many oil producing regions, the average air temperature is below 20 ° C throughout the year and reaches -40 ° C in winter, which complicates the requirements for the use of hydraulic fracturing fluids (hydraulic fracturing) with a temperature of at least 25 ° C and causes operational problems. At the same time, produced water produced from formations lying at a depth of more than 500-1000 meters and with temperatures from 35 ° C to 50 ° C is available in many fields, including Western Siberia, and is a source for the preparation of fracturing fluids: for the hydraulic fracturing method, treatment using low-viscosity fluids, for example, water with small amounts of thickener, at which the surface viscosity at ambient temperature is less than 10 cP, can be used.

According to the results of experimental studies, in order to extract the light oil contained in the rock from the rocks of the Bazhenov Formation, the thermal effect should be characterized by a temperature of up to 300-350 ° C, while a higher temperature, above 400 ° C, is necessary for the extraction of hydrocarbons from the solid phase - kerogen.

During the development of deposits by the method of thermogas exposure, with an increase in the water-air ratio (BBO), the value of the thermal rim and the speed of its movement increase while reducing the average temperature of the thermal rim. The BBO value of the injected oxygen-containing mixture and its injection rate are controlled based on mathematical modeling from the condition that it is necessary to heat the maximum possible volume of oil-containing non-draining matrix to a temperature of 250-300 ° C [see Kokorev V.I. Technical and technological foundations of innovative methods for developing fields with hard to recover and unconventional oil reserves. - Disser. for the degree doc. tech. sciences. - M., 2010].

Using a hydraulic fracturing fluid based on water containing condensate 8 released from the produced gas 7, a carbon dioxide solution can be obtained. The solubility of gases in water is different and depends on a number of factors: temperature, pressure, mineralization, the presence of other gases in an aqueous solution. As the temperature rises to 90 ° C, the solubility of gases in water decreases and then increases. So, 665 ml of carbon dioxide are dissolved in 1 liter of water at a temperature of 20 ° C, and at 0 ° C - three times as much, 1713 ml. An increase in pressure entails an increase in the solubility of gases. At a pressure of 2.5 MPa, 16.3 liters of carbon dioxide are dissolved in 1 liter of water, and at 5.3 MPa, 26.9 liters. By periodically increasing the heating temperature of methane-containing gas 16 due to the high concentration of carbon dioxide in methane-containing gas 16, the effect of increasing gas evolution directly in the formation 1 can be obtained, which will serve as an additional factor for oil displacement.

To provide an impact on the main hydrocarbon reserves in the kerogen-containing matrix, they also propose in the thermogas method of developing the resources of the Bazhenov formation, considered the most promising for Russia today.

According to the thermogas method, air and water are pumped into injection wells. Due to the high reservoir temperature in the Bazhenov formation, the combustion process self-initiates. Gaseous products of combustion and hot water provide a process of miscible displacement of oil in the liquid phase. The combustion front advancing in the formation leads to heating of the kerogen-containing matrix to a temperature of 250-300 ° C and to the processes of pyrolysis and cracking of kerogen with the extraction of oil and gaseous hydrocarbons. However, an increase in matrix permeability is accompanied by a simultaneous increase in its porosity, and the heating front slightly outstrips the high pressure front in the drained interlayer from the injection of air and water. Therefore, thermally “extracted” oil and gas can largely remain in the kerogen-containing matrix without entering the drained interlayers (see RF patent No. 2513963 for the invention, publ. 04/20/2014).

In the inventive method, the injected methane-containing gas 3 with a volumetric content of methane in the flow of methane-containing gas 3 in the range of 33-48%, hydrogen - 35-44% per dry gas will come into the kerogen-containing matrix due to filtration and diffusion processes, interact with bound hydrocarbons , leading to their swelling and “extrusion” from the matrix into drained interlayers, under the regime of miscible displacement due to high thermobaric conditions in the Bazhenov formation. Moreover, the oil reservoir 1, thus, due to the high concentration of hydrogen in the methane-containing gas 3 and high temperature is subjected to soft non-catalytic (for example, thermal and / or thermomechanical) cracking or visbreaking.

Due to the high concentration of hydrogen in methane-containing gas 3, mercaptans, sulfides and disulfides are easily hydrogenated under relatively mild conditions. In cyclic organosulfur compounds, under the influence of hydrogen, saturation occurs, followed by ring breaking and the formation of the corresponding paraffinic or alkyl aromatic hydrocarbon.

Oxygen-containing organic compounds usually easily enter into hydrogenation reactions with the formation of the corresponding hydrocarbons and water. Complex resinous and asphaltene substances of oil and oil residues contain a lot of oxygen and therefore their conversion into hydrocarbon products is much more difficult. Of the oxygen-containing compounds, the most important are resins and asphaltenes, which, when hydrogenated, turn into lower molecular weight hydrocarbons and water. In addition to these compounds, phenols and naphthenic acids may be present in different raw materials, during the hydrogenation of which due to the high concentration of hydrogen in methane-containing gas 3 the corresponding hydrocarbons and water are formed.

Destructive hydrogenation is a one- or multi-stage catalytic process of hydrogen addition under pressure, accompanied by the splitting of high molecular weight components of the feed and the formation of low molecular weight hydrocarbons. Non-destructive hydrogenation is a one-stage catalytic process to which all types of distillate feedstock can undergo. As a result, they, without being subjected to cleavage, improve their properties: they are mainly freed from unsaturated hydrocarbons. This occurs due to the high temperature (above 400 ° C) with a high concentration of hydrogen in the methane-containing gas 3.

This allows you to reduce the need for air when developing deposits using the thermogas method and reduce the cost of oil production, since the share of the cost of pumping air in the total cost of oil production reaches 30-40%.

Since CO ₂ is removed from the atmosphere into reservoir 1, this technology can be considered as one of the methods of sequestering carbon dioxide and reducing the so-called greenhouse effect.

The use of methane-containing gas 3 with a high content of steam and a hydrocarbon solvent according to the proposed technology for joint injection into the formation 1, as shown by the research results, creates this composition a high dissolving ability with respect to heavy oils, the ability to reduce interfacial tension at the heavy oil-water interface low corrosion activity in relation to oil equipment, lack of sedimentation of asphalt-resinous substances of heavy oils in this solvent, ability lowers the stability of oil-water emulsions. At the same time, the accumulated steam-oil ratio decreases by 1.3 times.

In combination with the claimed method, various technical and technological means for implementing the technology can also be used:

- the use of horizontal and horizontally branched wells;

- sidetracking;

- the formation of branched side drains;

- the use of hydraulic fracturing of various designs, including directed;

- production of slotted unloading of bottom-hole zones;

- thermal and thermogasochemical effects on the bottomhole zone;

- cyclic effect.

Distribution of methane-containing gas 3 through pipelines is well mastered in the chemical industry and allows increasing the power of an energy source, for example, a nuclear reactor when used in thermal methods to increase oil recovery, which will further improve the efficiency of the technology.

Thus, this method will create conditions for effectively increasing the utilization of energy resources with the ability to maintain high reservoir pressure in the productive layers of viscous oil by injecting methane-containing gas 3 displacing oil, reduce energy consumption, reduce the cost of pumping it and the losses associated with the release of excess heat to the atmosphere, improve the economic performance of viscous oil production.

Claims (7)

1. A method of developing a heavy oil deposit, including drilling production and injection wells and injecting methane-containing gas into the formation, in which the produced gas, after separation, is injected back into the formation, characterized in that prior to pumping the produced gas into the formation, it is catalytically converted to produce heated methane-containing gas containing water vapor, carbon dioxide and hydrogen. 2. The method according to p. 1, characterized in that the catalytic conversion is carried out by supplying heated water vapor and thermal energy from an external energy source in which nuclear and / or organic fuel is burned. 3. The method according to p. 1, characterized in that the associated gas used is associated petroleum gas produced from a heavy oil reservoir. 4. The method according to p. 1, characterized in that the feed water for producing water vapor is supplied from a reservoir replenished with condensate released from the produced gas. 5. The method according to p. 1, characterized in that the temperature regime of the catalytic conversion is supported by changing the flow rate and composition of the produced gas. 6. The method according to p. 1, characterized in that the injection of methane-containing gas is accompanied or alternated with the injection of solvents, in the form of rims or by enrichment of the methane-containing gas with a solvent. 7. The method according to p. 1, characterized in that the methane-containing gas is injected periodically, supplying air and / or hydraulic fracturing fluid based on water containing produced water produced from the formation at intervals into the formation.

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