RU2792453C1 - Method of hydrodynamic stimulation of the formation to increase oil recovery - Google Patents

Abstract

FIELD: oil industry.

SUBSTANCE: invention relates to a method for hydrodynamic stimulation of a formation to increase oil recovery. The method of hydrodynamic stimulation for increasing oil recovery from formations includes the selection of water and liquid hydrocarbons through production wells and the injection of a working agent through injection wells. Field data on the operation of each well are registered. Based on field data on well operation, machine learning methods reproduce measurements of water and hydrocarbon production. In the process of multivariate calculations, the modes of injection of the displacing fluid and the modes of operation of producing wells are selected, which provide the highest cumulative production of hydrocarbons. The modes are laid in a three-dimensional hydrodynamic simulator that combines neural networks and a geological and hydrodynamic model, which allows you to generate the values of injectability and fluid flow rates and issue commands for controlling wells in manual or automatic mode. The influence of injection of a water-gas mixture into the reservoir is measured with the determination of the volumes and ratios of water and gas in the mixture, as well as wells that are hydrodynamically interconnected. The injection of the working agent into injection wells is carried out with the control of bottom hole pressures in production wells. When the bottom hole pressure in the production well decreases, the injection wells hydrodynamically connected with this production well are injected with a water-gas mixture for 4–5 days per month until the bottom hole pressure is restored, after which the injection of the water-gas mixture is stopped until the bottom hole pressure in one of the production wells decreases.

EFFECT: expanding the functionality of the hydrodynamic impact on the reservoir through the use in reservoirs with different structure and reservoir pressure, as well as to increase the effectiveness of the impact on the reservoir.

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Description

The invention relates to the oil industry, in particular to methods for influencing oil reservoirs with a water-gas mixture to increase oil recovery from reservoirs.

A known method of influencing a heterogeneous oil reservoir (patent RU No. 2103484, IPC E21B 43/18, publ. water-gas mixture with a ratio of water and gas volumes of 1:1, simultaneously with the injection of the mixture periodically every 12 months, counting from the beginning of injection, select production wells that satisfy the following expressions:

r _n > 0.5,

r _in < 0.5,

r _g < 0.5,

where r _n , r _in , r _g - Spearman's rank correlation coefficients, respectively, between the flow rates of liquid and oil, liquid and water, liquid and monthly values of the gas factor in a given well, determined in accordance with the expressions

where d, n, i, d, c, i, d, d, i are the differences, respectively, of the ranks of the flow rates of liquid and oil, liquid and water, liquid and gas factor in a given well;

n 12 the number of monthly flow rates of liquid, oil, water and gas factor in this well during the year,

and then produce an increase in fluid withdrawals from the selected production wells.

The disadvantages of this method are the narrow scope due to the rigid ratio of 1:1 injected volumes of water and gas, which is unacceptable for a well with high reservoir pressure (above 10 MPa), since it requires large volumes of gas to comply with the ratio, which in reservoir conditions is intensive is released and forms hydraulic seals that reduce the oil recovery of the reservoir, isolating individual sections of the reservoir from the hydrodynamic impact, delaying the changing situation of the hydrodynamic state of the reservoir by at least 1 year (12 months), which leads to a decrease in the effectiveness of the impact on the reservoir.

There is also known a method for pumping aerated liquid into a reservoir (patent RU No. 2347894, IPC E21V 43/20, publ. 27.02.2009 Bull. No. 6), including mixing gas with liquid, transporting aerated fluid through an independent well channel and pumping it into the reservoir , moreover, after mixing the gas with the liquid, the carbonated liquid is dispersed with active mixing and subsequent transfer to a laminar flow, and transport through an independent channel is carried out at a speed that provides a laminar flow of the carbonated liquid.

The disadvantages of this method are the narrow scope due to the possibility of working only in massive homogeneous reservoirs, since there is no complete control and response to the changing situation of the hydrodynamic state of the reservoir, which leads to a decrease in the effectiveness of the impact on the reservoir.

The closest in technical essence is a method for increasing the production of liquid hydrocarbons by methods of maintaining reservoir pressure during the injection of a displacing fluid and increasing the efficiency of hydrodynamic methods of influencing the reservoir (patent RU No. 2859143, IPC E21B 47/10, publ. 09.11.2021 Bull. No. 31), enhanced oil recovery (OR) and oil production, which includes the selection of water and liquid hydrocarbons through production wells and the injection of a working agent through injection wells, registration of field data on the operation of each well, on the basis of which historical production measurements are reproduced using machine learning methods water and hydrocarbons, in the process of multivariate calculations, the optimal modes of injection of the displacing fluid and operating modes of producing wells are selected, providing the highest cumulative production of hydrocarbons, the optimal modes are put into a three-dimensional hydrodynamic simulator, in which a predictive calculation is carried out and the final commands for controlling wells in manual or automatic mode, and for the final setting of the optimal well operation modes, a combination of a neural network and a geological and hydrodynamic model is used, which makes it possible to form the optimal values of injectivity and fluid flow rates to control the redistribution of water injection, based on the geological and hydrodynamic model and given optimal injectivity and liquid flow rates, the forecast oil production and additionally produced oil are calculated through the use of hydrodynamic methods for enhanced oil recovery.

The disadvantages of this method are a narrow scope due to the low efficiency of working with fields with low reservoir pressure, since the injection of water-gas mixtures is not used to increase the in-situ pressure during the injection of a displacing agent, and only the results of neural network and three-dimensional calculations are used to predict and determine injection modes. geological and hydrodynamic model, which, as practice has shown, leads to a delay in the changing situation of the hydrodynamic state of the reservoir by at least 2 months. and reducing the effectiveness of the impact on the formation.

The technical objective of the proposed invention is to create a method of hydrodynamic stimulation of the reservoir to increase oil recovery, which allows expanding the functionality by increasing the scope for reservoirs of various structures and pressures, by pumping every month for 4-5 days of a water-gas mixture with a decrease in reservoir pressure, as well as increase the efficiency of reservoir stimulation by injecting a water-gas mixture and a displacing agent with pressure control in the zone of each well with a real-time response to changes in bottom-hole pressure in production wells.

The technical problem is solved by the method of hydrodynamic stimulation of the reservoir to increase oil recovery, including the selection of water and liquid hydrocarbons through production wells and the injection of a working agent through injection wells, the registration of field data on the operation of each well, on the basis of which water and hydrocarbon production measurements are reproduced using machine learning methods, at the same time, in the process of multivariate calculations, the modes of injection of the displacing fluid and the modes of operation of producing wells are selected, providing the highest cumulative production of hydrocarbons, the selected modes are put into a three-dimensional hydrodynamic simulator that combines neural networks and a geological and hydrodynamic model that allows you to form the values of injectivity and fluid flow rates to control redistribution injection of a working agent, and in a hydrodynamic simulator based on a geological and hydrodynamic model, given injectivity and fluid flow rates, a predictive calculation is carried out and output commands for well control in manual or automatic mode.

What is new is that they measure the effect of pumping a water-gas mixture into a reservoir with the determination, after analyzing the volumes and ratios of water and gas in the mixture to enhance oil recovery, as well as wells that are hydrodynamically interconnected, the injection of a working agent into injection wells is carried out with control of bottomhole pressures in production wells, with a decrease in bottomhole pressure in a production well, a water-gas mixture is injected into injection wells hydrodynamically connected with this production well within 4–5 days a month in a volume and ratio that ensures the restoration of bottomhole pressure in the production well, after which injection the water-gas mixture is stopped until the bottom-hole pressure in one of the production wells decreases, while an automatic workplace system is used to automatically control the injection modes, and each injection well is equipped with electrically controlled cranes that respond to matic workplace signals.

What is also new is that dried associated petroleum gas is used as gas in the water-gas mixture.

In FIG. 1 shows a diagram of the reservoir pressure maintenance system (RPM) of the Podgorny area of the Republic of Tatarstan (RT).

In FIG. 2 shows a part of the table of data received every minute from producing wells in the Podgorny area of the Republic of Tatarstan.

In FIG. 3 shows a digital desktop for controlling the RPM system of the Podgorny section of the Republic of Tatarstan.

In FIG. 4 shows a diagram of the wellhead fittings of the injection well of the Podgorny section of the Republic of Tatarstan.

The method of hydrodynamic impact to increase oil recovery is implemented in the following sequence.

Production and injection wells of the oil field are equipped with measuring instruments and field data are recorded on the operation of each well, for example, pressure sensors, fluid flow (working agent (fresh water, saline water, water with reagents, etc.) for injection wells and production of wells with hydrocarbon content in water for production wells), level gauges (to control liquid level recovery curves - KVU after the shutdown of the corresponding wells), etc. Periodically, a water-gas mixture (WGM) is pumped into the injection wells selected by the technologists with a change in the proportions of water and gas, as well as pressures and injection volumes. field data on the operation of each well are summarized in a database (DB) and analyzed for at least one year (the longer the evaluation period, the more accurate the result). Based on the obtained data, the historical measurements of water and hydrocarbon production are reproduced by machine learning methods, in the process of multivariate calculations, the optimal modes of injection of the working agent (displacing fluid) and the operating modes of production wells (including the optimal bottomhole pressure) are selected, providing the highest cumulative hydrocarbon production ( maximum oil recovery). Wells are also determined hydrodynamically interconnected, in which a change in the operation parameters of one of the wells affects the operation parameters of the remaining wells, and the volumes and ratios of water and gas in the WGM that are optimal for increasing oil recovery in the WGM when it is injected into the reservoir. The gas used in VGD is atmospheric air for most deposits, inert gases (most often Nitrogen - N) for explosive deposits, or purified and dried associated petroleum gas (most often it is a methane-propane-ethane-butane mixture) for deposits prone to asphaltene deposition , resins and paraffins (ARPO) or deposits with bituminous oil, since petroleum gas is also a good solvent. Optimal modes are laid in a three-dimensional hydrodynamic simulator that combines a neural network and a geological and hydrodynamic model, which makes it possible to form the optimal values of injectivity and fluid flow rates to control the redistribution of water injection. In a hydrodynamic simulator, based on a geological and hydrodynamic model, given optimal injectivity and fluid flow rates, a predictive calculation is carried out and final commands are issued for well control in manual or automatic mode. The injection of the working agent into injection wells is carried out with the control of bottomhole pressures in production wells. When the bottom hole pressure in any production well drops below the optimum, injection wells hydrodynamically connected with this production well are injected in the optimal volume and ratio of WGM in several stages of 4–5 days per month until the optimal bottomhole pressure in the production well is restored. As the practice of using WGM injection at the fields of the Republic of Tatarstan to increase the intra-formation pressure has shown, it is optimal to pump periodically for 4-5 days (depending on the required optimal volume of WGM without disturbing the integrity of the reservoir) per month until the optimal bottomhole pressure is restored, as it allows maintaining the optimal bottomhole pressure. pressure for a period of 2–4 times longer than with a single injection of WGM, but in large volumes, since the compressed gas is evenly distributed over the reservoir with the option of WGM injection proposed by the authors. Since the reaction to the changing situation with reservoir pressure in a particular area occurs immediately after the bottomhole pressure drop, it is possible to constantly maintain a stable displacement front in real time (regardless of the structure of the reservoir and its in-situ pressure) and obtain additional oil recovery (hydrocarbon production) from productive formation.

Example of a specific implementation

The proposed method was implemented at the Alekseevsky oil field of the Podgorny section of the Republic of Tatarstan by a closed joint-stock company (CJSC). Aloil.

Since the production of the reservoir is prone to the formation of ARPD for injection into the reservoir, it was decided to use petroleum gas. To do this, according to the scheme (Fig. 1), a PPD system was implemented. As water intake wells 1, wells are used in a highly watered section of the field, which are equipped with a controlled electric centrifugal pump (ECP) with a control station with a frequency converter (not shown) to produce the required amount of water for injection using booster pumps 2 (CNS-38) into injection wells (not shown) through the pipeline 3. Water from the water well 1 is fed to the intake of the oil and gas separator 4 (NGS-80) for degassing. Degassed water from the oil and gas separator 4 (NGS-80) flows by gravity through a filter (not shown) to the intake of the booster pump 2 of the central pumping station (CPS), which is the booster for the booster pump unit 5 (NBU), where petroleum gas is stored. In parallel, at the booster pumping station 6 (DNS-260), the water-gas-oil emulsion coming through the inlet pipelines 7 is degassed in the oil and gas separator 8 (NGS-50) of the booster pumping station 5. The gas released in the oil and gas separator 8 enters the gas separator 9 (GS-2) for drying and further through the gas compressor station 10 (GCS) to NBU 5 for storage and mixing with water supplied by booster pump 2. The gas-air mixture prepared in NBU 5 through pipeline 3 further to injection wells. The separated liquid phase (oil, water, reagents and/or the like) from the oil emulsion from the oil and gas separator 8 is sent through the outlet pipeline 11 to the booster pump station (not shown) and further to the oil treatment unit (not shown)

All data from sensors installed at the wellhead and inside the wells is fed into a single database (Fig. 2), after which it is processed. Based on the obtained data, the historical measurements of water and hydrocarbon production are reproduced by machine learning methods, in the process of multivariate calculations, the optimal modes of injection of the working agent (displacing fluid) and the operating modes of production wells (including the optimal bottomhole pressure) are selected, providing the highest cumulative hydrocarbon production ( maximum oil recovery). The optimal modes are laid in a three-dimensional hydrodynamic simulator (for example, in the tNavigator, SMG software package, etc.), which combines a neural network and a geological and hydrodynamic model, which makes it possible to form the optimal values of injectivity and fluid flow rates to control the redistribution of water injection (for example, SCADA - a system that describes an algorithm designed to provide a job, or the like). In the hydrodynamic simulator, based on the geological and hydrodynamic model, given optimal injectivities and fluid flow rates, a predictive calculation is carried out and final commands are issued to control the pressure maintenance control system in manual or automatic mode (for example, using the automatic workstation system - AWP "Telemechanika", Fig. 3 or similar). For automatic control of injection modes, each injection well 12 (Fig. 4) on the inlet pipeline 13 is equipped with electrically controlled valves 14, which respond to signals supplied from the workstation (not shown), pressure sensors 15, and mechanical valves 16 in case of failure of the valve 14 .

The following control signals are provided:

1. "ACCIDENT" stops the NBU and GKS, the open wellhead valves are automatically closed.

2. Start/stop. Allows you to control the production process of pumping the working agent or HCV.

The required volume and proportions of the working agent or VGM for injection into the reservoir are prepared in special containers and mixers in NBU 5 (Fig. 1).

With a decrease in bottomhole pressure in one of the production wells (not shown) below the optimum (7.1 MPa), after turning off the supply of the working agent (mineralized water), the dried gas after the gas separator 9 (GS-2) was fed to the compressor of the gas compressor station 10 (GCS) which injects gas into NBU 5 for mixing with water and obtaining WGM in the optimal proportion and volume through pipeline 3 for injection into productive formations (not shown) through injection wells hydrodynamically connected with this production well. WGM injection was carried out in several stages (usually 3-4), the first two stages were four (4) days per month, the last - 5 days each, since the formation injectivity decreased, and division above the critical one, at which the integrity of the formation is violated, is not allowed . After that, the bottom-hole pressure in the production well became slightly higher than the optimal one (7.3 MPa), and the injection of WGM was replaced by the injection of a working agent (water, mineral water, water with surfactants, and/or the like).

The use of this method by Oloil CJSC made it possible to increase the cumulative production at the Alekseevskoye field from the moment of implementation by more than 90 thousand tons as of July 1, 2020 alone, compared to the closest analogue.

The proposed method of hydrodynamic stimulation of the reservoir to increase oil recovery allows expanding the functionality by increasing the scope for reservoirs of different structure and pressure, due to the injection of a water-gas mixture every month for 4-5 days with a decrease in reservoir pressure, as well as increasing the effectiveness of the impact on the reservoir for injection of a water-gas mixture and a displacing agent with pressure control in the zone of each well with a response to changes in bottom-hole pressure in production wells in real time.

Claims (2)

1. A method for hydrodynamic stimulation of a formation to increase oil recovery, including the selection of water and liquid hydrocarbons through production wells and the injection of a working agent through injection wells, the registration of field data on the operation of each well, on the basis of which water and hydrocarbon production measurements are reproduced using machine learning methods, with At the same time, in the process of multivariate calculations, the displacement fluid injection modes and production well operation modes are selected that provide the highest cumulative hydrocarbon production, the selected modes are put into a three-dimensional hydrodynamic simulator that combines neural networks and a geological and hydrodynamic model that allows you to form the values of injectivity and flow rates of the fluid to control the redistribution of injection working agent, and in the hydrodynamic simulator, based on the geological and hydrodynamic model, given injectivity and fluid flow rates, a predictive calculation is carried out and commands are issued to control the well gins in manual or automatic mode, characterized in that they measure the effect of injection of a water-gas mixture into the reservoir with the determination, after analyzing the volumes and ratios of water and gas in the mixture to enhance oil recovery, as well as wells that are hydrodynamically interconnected, the injection of a working agent into injection wells are produced with control of bottomhole pressures in production wells, with a decrease in bottomhole pressure in a production well, a water-gas mixture is injected into injection wells hydrodynamically connected with this production well within 4-5 days a month in a volume and ratio that ensures the restoration of bottomhole pressure in the production well well, after which the injection of the water-gas mixture is stopped until the bottom-hole pressure in one of the production wells decreases, while an automatic workplace system is used to automatically control the injection modes, and each injection well is equipped with electrically controlled cranes , which react to the signals given from the automatic workplace. 2. The method of hydrodynamic impact on the formation to increase oil recovery according to claim 1, characterized in that dried associated produced gas is used as gas in the water-gas mixture.

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