RU2816602C1 - Oil deposit development method - Google Patents

Abstract

FIELD: mining; oil industry.

SUBSTANCE: invention relates to development of oil deposits at late stage of development. Method of development of oil deposit, exposed by injection wells and at least two production wells, includes pumping of working agent through injection wells and extraction of liquid through production wells. At the same time residual recoverable oil reserves are determined for the section of the deposit and the compartmentalization factor for the production facility. At a later stage of development, a section of the deposit with residual recoverable oil reserves of at least 3,000 t is selected, with coefficient of compartmentalization in production section of deposit more than 1.25 in at least one well, current average formation pressure is less than initial formation pressure on deposit, average porosity of productive deposits for wells is from 0.12 to 0.26. On the deposit section, selecting a production well with a current flow rate below the average production rate of production wells of the selected section, selected production well is changed over to injection well provided that there is at least one production well of operating well stock within radius of 800 m from the selected production well. Further, the working agent is pumped into the selected well in stages with duration at each stage from 1 to 6 months.

EFFECT: higher efficiency of development of oil deposit at late stage of development.

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Description

The invention relates to the oil industry, in particular to the field of development of oil deposits at a late stage of development and can be used in the development of oil deposits with a terrigenous reservoir separated by an impermeable clayey or clayey low-permeability bridge.

There is a known method for developing a watered, zonally heterogeneous oil field (patent RU No. 2208139, E21B 43/20, published July 10, 2003, Bulletin No. 19), which includes opening at least one injection and several production wells. Slugs of an agent that increases the filtration resistance of the porous medium and water are pumped into the injection well. Change the operating mode of production and injection wells during the injection of reagents. In this case, the production well located in the clay reservoir is turned off. A slug of an agent that increases the filtration resistance of the porous medium and a portion of a slug of a stabilizing composition are sequentially pumped into the injection well. Then the injection well is turned off and a time delay sufficient to redistribute the filtration flows is allowed. After this, the production well located in the clay reservoir and the injection well are opened. Pump in the second portion of the stabilizing composition. Then they switch to normal waterflooding. The injection pressure in the injection well is maintained constant, corresponding to the pressure of production from the production wells.

The disadvantage of this known method is the limitation on the required formation characteristics for successful injection of slugs, and the high cost of chemical reagents.

There is also a known method for developing an oil deposit with a clay reservoir (patent RU No. 2527949, MPK E21B 43/16, published 09/10/2014, Bulletin No. 25), including pumping a working agent through injection wells and sampling reservoir products through production wells. For development, a deposit or a section of a deposit is selected with a reservoir pressure not lower than the initial one, a water cut of 60% more, and recoverable reserves of at least 40 thousand tons. Then, a retrospective analysis is carried out for this section on changes in the dynamics of reservoir and bottomhole pressures and the least developed section with content clay fraction from 2.5% or more. After the analysis, several design points for drilling vertical injection wells are replaced with one injection well with a horizontal end. A horizontal shaft is placed in a formation with a strike thickness of at least 3 m. The shaft is installed at the boundary of the transition of the reservoir rock from clayey sandstone to siltstone. After putting a horizontal injection well into operation, liquid is injected into the formation with constant monitoring of changes in the operating mode of surrounding production wells by measuring bottomhole pressure and water cut. After an increase in bottomhole pressure sufficient to intensify product selection, work is carried out to optimize downhole pumping equipment to a larger standard size. After the analysis, several design points for drilling vertical production wells are replaced with one production well with a horizontal end. A horizontal shaft is placed in a formation with a strike thickness of at least 3 m. The shaft is installed at the boundary of the transition of the reservoir rock from clayey sandstone to siltstone. After putting a horizontal production well into operation, fluid is withdrawn from the formation with constant monitoring of changes in the operating mode of surrounding production wells by measuring bottomhole pressure and water cut of the product. After the bottomhole pressure is reduced by 10% below the saturation pressure, work is carried out to increase injection through the influencing injection wells.

The disadvantage of the known method is that they do not determine the drainage areas of production wells, do not identify the boundaries of zones with residual oil reserves in the interwell space, the development of the deposit is carried out by drilling new horizontal wells of great length, each of which replaces several design points for drilling vertical wells, which leads to to an increase in material costs for well construction.

There is also a known method for developing an oil deposit at a late stage of development (patent RU No. 2595112, IPC E21B 43/20, published on August 20, 2016, Bulletin No. 23), including determining the remaining oil reserves in the interwell space, drilling additional production lateral and lateral horizontal wells, opening of residual oil-saturated intervals, injection of a displacing agent through injection wells and selection of products through production wells. According to the method, a flooded oil reservoir is selected, from which ≥80% of recoverable oil reserves have been selected, with oil-saturated thicknesses of ≥2 m; based on the results of geophysical studies of wells, laboratory core studies, zones with low-productive rocks discovered by neighboring wells are identified, drainage areas of production wells are determined to determine the boundaries of the zone with residual profitable oil reserves in the interwell space, in the direction of which additional production lateral and lateral horizontal trunks are drilled from nearby production wells with the least production of reserves, and the length of the lateral and lateral horizontal trunks does not exceed the distance between adjacent wells. If there is more than one oil-saturated formation in the section of neighboring wells, in each of which there is a zone with residual profitable oil reserves, a sidetrack is drilled to open all these zones.

The disadvantages are the high cost of drilling new wells, the risk of failure of drilling lateral and horizontal trunks in heterogeneous deposits.

The closest is the method of developing an oil deposit (patent RU No. 2066369, MPK E21B 43/20, published on September 10, 1996), opened by injection and production wells, including pumping a working agent through injection wells and withdrawing liquid (oil) through production wells, cyclic mode of injection of the working agent through injection wells and withdrawal of oil through production wells at a late stage of development; when performing a cyclic mode at a late stage of development for 2-6 months, injection of the working agent through injection wells is carried out with its volumes exceeding the volumes of fluid withdrawn through production wells wells and until the reservoir pressure increases by less than 3% of the current average reservoir pressure, then for 2-6 months, fluid is withdrawn through production wells with its volumes exceeding the volumes of injection of the working agent through injection wells and until the reservoir pressure decreases by less than 3% of the current average reservoir pressure.

The disadvantages are the limited use of cyclic flooding due to technical limitations of pumping units and the productivity coefficient of injection wells, as well as the difficulty of involving in the development of previously undeveloped zones of the deposit, as a result of which the oil recovery of the deposit remains at a low level.

The technical objectives are to increase the efficiency of oil reservoir development at a late stage of development by displacing hydrocarbon reserves by changing the direction of the main filtration flows and involving poorly drained, low-permeability areas of the productive reservoir in the development, by maintaining optimal energy indicators in the deposits, as well as increasing the oil recovery factor.

Technical problems are solved by a method for developing an oil reservoir discovered by injection wells and at least two production wells, including pumping a working agent through injection wells and withdrawing fluid through production wells.

What is new is that the residual recoverable oil reserves for the deposit area and the compartmentalization coefficient for the production site are determined; at a late stage of development, a deposit area with residual recoverable oil reserves of at least 3000 tons is selected, with a compartmentation coefficient for the production site of the deposit of more than 1.25, at least in one well, the current average reservoir pressure is less than the initial reservoir pressure on the deposit, the average porosity of productive sediments for wells is from 0.12 to 0.26, a production well with a current flow rate lower than the average flow rate of the production wells of the selected area is selected in the reservoir area, the selected production well is transferred into the injection well, provided that there is at least one production well of the operating stock within a radius of 800 m from the selected production well, the working agent is injected into the selected well as follows: in an amount of 40-200% of the volume of the withdrawn liquid for 1 month, in an amount of 60- 200% of the volume of sampled fluid for 2 months, in an amount of 80-200% of the volume of sampled fluid for 2 months, in an amount of 100-200% of the volume of sampled fluid for 6 months, in an amount of 120-200% of the volume of sampled liquid for 5 months, in an amount of 140-200% of the volume of selected liquid for 4 months, in an amount of 160-250% of the volume of selected liquid for 3 months, in an amount of 180-300% of the volume of selected liquid for 2 months , in an amount of 200-300% of the volume of fluid taken for 1 month.

The method for developing an oil deposit is carried out as follows.

When developing an oil reservoir at a late stage of development, areas with low reservoir pressure appear. As a result, there is a decrease in the operating coefficient, the utilization rate of the well stock as a result of the aging of the well stock and the failure of production strings, an increase in the excess stock and a decrease in the rate of oil recovery. Part of the mobile reserves of hydrocarbon raw materials remains not extracted from the reservoir media. Therefore, when developing oil deposits with a terrigenous reservoir (with absolute permeability from 50 * 10-3 µm ² to 1.2 µm ² ) at a late stage of development, it is necessary to increase the efficiency of oil deposit development, displacing hydrocarbon reserves (oil) and involving the development of poorly drained low-permeability areas of the productive reservoir.

An area of an oil deposit is drilled according to the design grid with at least two production and injection wells. The oil deposit is exploited in a natural mode until the level of reservoir pressure decreases (as a rule, a decrease in pressure is observed to values of 0.4-0.9 from the initial reservoir pressure) with a subsequent transition to the mode of artificial maintenance of reservoir pressure with the organization of partial compensation of fluid withdrawals by injection of working fluid. agent. Within the section of at least one of the wells in the area, reservoir layers are distinguished, separated by an impermeable clayey or clayey low-permeability bridge. The productive reservoir is composed of terrigenous rocks, predominantly polymictic sandstones of the greywacke type. At the same time, the absolute permeability of productive layers differs by more than 1.2 times.

Low-mineralized water from surface water sources (for example, a river network, under-river water intakes, etc.), specially produced formation water and produced water from oil treatment facilities (hereinafter referred to as water) are used as a working agent for displacement. The mineralization of injected water varies from 200 mg/l to 285 g/l. Subsequent compaction of the well pattern beyond that provided for in the project is allowed. Residual recoverable oil reserves for the deposit area and the compartmentalization coefficient for the production facility are determined.

When the extraction of recoverable oil reserves reaches more than 55%, a deposit area with residual recoverable oil reserves of at least 3000 tons is selected, with a compartmentation coefficient for the production facility (reservoir area) of more than 1.25 in at least one well (this value of the compartmentation index for the deposit area indicates uneven distribution of reservoir layers, contributing to the formation of poorly drained zones), the current average reservoir pressure at existing production wells is less than the initial reservoir pressure on the deposits, characterizing a decrease in the energy potential of the deposit (the higher the difference between the initial reservoir pressure and the current one, the higher the expected effect) , the average porosity of productive sediments for wells is from 0.12 to 0.26 (the presented range of porosity values ensures free filtration of formation fluid, with an average porosity below 0.12 - it will not be accepted, with an average porosity above 0.26 - the use of this method is inappropriate ). In the deposit area, a production well is selected with a current flow rate below the average flow rate of the production wells of the selected area and the selected production well is converted into an injection well for injection of the working agent, provided that there is at least one production well of the operating stock within a radius of 800 m from the selected production well.

The selected production well is launched for injection to organize a differentiated level of compensation for the withdrawn liquid (oil), and the injection of the working agent - water - is carried out in stages, lasting at each stage from 1 to 6 months. Injection of the working agent into the selected well is carried out as follows: in an amount of 40-200% of the volume of fluid withdrawn at the site for 1 month, then in an amount of 60-200% of the volume of fluid withdrawn at the site for 2 months, then in an amount of 80- 200% of the volume of fluid sampled on the site for 2 months, then in the amount of 100-200% of the volume of fluid sampled in the site for 6 months, then in the amount of 120-200% of the volume of fluid sampled in the site for 5 months, then in an amount of 140-200% of the volume of fluid sampled at the site for 4 months, then in an amount of 160-250% of the volume of fluid sampled at the site for 3 months, then in an amount of 180-300% of the volume of fluid sampled at the site for 2 months, then in an amount of 200-300% of the volume of liquid taken at the site for 1 month.

When implementing the proposed working agent injection scheme, step-by-step compensation of the withdrawn liquid is ensured. So, for example, when withdrawing liquid (oil) 100 ^m3 /day, we start pumping from 40 ^m3 /day to 200 ^m3 /day, then increase the lower threshold by 20% and pump from 60 ^m3 /day to 200 ^m3 /day and further according to the proposed scheme. The choice of the required range was determined experimentally, ensuring effective displacement of oil from previously trapped in low-permeability zones of the reservoir.

As a result of the proposed stage-by-stage injection of the working agent (water), the reservoir pressure in the area increases from that achieved at the previous stage by an amount from 20% to 89% and the steady filtration flows in the reservoir environment change. Due to changes in reservoir energy (formation pressure) with a difference in the elastic properties of rocks and formation fluid phases, the increased pressure gradient ensures the beginning of the movement of hydrocarbon raw materials (oil), previously trapped in poorly drained low-permeability zones of the reservoir, ensuring the achievement of target values of the oil recovery factor, preventing an increase rate of decline in base oil production. As a result, an increase in the oil recovery factor, oil recovery factor (i.e., oil recovery) is ensured while simultaneously extending the period of profitable operation of production wells.

Examples of practical application.

Example 1.

The terrigenous area, where 8 production wells and 1 injection well are located, has the following parameters:

• Residual recoverable oil reserves amount to 4321 tons.

• The coefficient of fragmentation for the production area of the deposit is 2.25

• 8 production wells in operation

• Current average reservoir pressure at production wells is 110 atm (initial pressure - 175 atm)

• Average porosity - 0.12

• Reservoir layers are distinguished, separated by an impermeable clayey or clayey low-permeability bridge. At the same time, the absolute permeability of productive layers differs by 1.5 times.

We selected production well No. 1, operating with a current flow rate of 0.5 t/day (with an average flow rate over the area of 2.5 t/day) and a water cut of 98%. At the same time, production wells No. 2, 3, 4 operate within a radius of up to 800 m with an average oil flow rate of 2.7 tons/day and a volume of withdrawn liquid of 100 ^m3 /day.

After transferring production well No. 1 to injection, reservoir injection was carried out with the following operating modes: 40 m ³ /day for 1 month, 60 m ³ /day for 2 months, 80 m ³ /day for 2 months, 100 m ³ / day for 6 months, 120 m ³ / day for 5 months, 140 m ³ / day for 4 months, 160 m ³ / day for 3 months, 180 m ³ / day for 2 months, 200 m ³ / days for 1 month. As a result, the following results were obtained: the average reservoir pressure rose to 152 atm (+38%), the average flow rate for wells No. 2, 3, 4 was 3.9 t/day. There was an increase in oil recovery factor by 36%.

Example 2.

The terrigenous area, where 3 production wells and 1 injection well are located, has the following parameters:

• Residual recoverable reserves amount to 4005 tons.

• The coefficient of fragmentation in the production area of the deposit is more than 1.3

• 3 production wells in operation

• The current average reservoir pressure at production wells is 175 atm. (initial pressure – 175 atm.). No decrease in reservoir pressure is observed

• Average porosity - 0.25.

• Reservoir layers are distinguished, separated by an impermeable clayey or clayey low-permeability bridge. At the same time, the absolute permeability of productive layers differs by 1.3 times.

Due to the lack of reduction in reservoir pressure at the site, the implementation of the proposed development method is impractical. An effective system for maintaining reservoir pressure has been organized.

Example 3.

The terrigenous area, where 2 production and 1 injection wells are located, has the following parameters:

• Residual recoverable reserves amount to 3000 tons.

• The separation coefficient for the production area of the deposit is 1.25 production wells in operation

• The current average reservoir pressure at production wells is 100 atm. (initial pressure - 170 atm.).

• Average porosity - 0.19

• Reservoir layers are distinguished, separated by an impermeable clayey or clayey low-permeability bridge. At the same time, the absolute permeability of productive layers differs by 1.6 times.

We selected production well No. 1, operating with a current flow rate of 0.5 t/day (with an average flow rate of 1.5 t/day for the site) and a water cut of 99%. At the same time, production well No. 2 operates within a radius of up to 800 m with an oil flow rate of 2.5 tons per day and a volume of withdrawn liquid of 50 m ³ / day.

After the production well No. 1 was transferred to injection, injection was carried out with the following operating modes: 60 m ³ /day for 1 month, 65 m ³ /day for 2 months, 70 m ³ /day for 2 months, 75 m ³ /day for 6 months , 80 m ³ /day for 5 months, 85 m ³ /day for 4 months, 103 m ³ /day for 3 months, 120 m ³ /day for 2 months, 125 m ³ /day for 1 month. As a result, the following results were obtained:

The average reservoir pressure rose to 165 atm (+50%).

The oil flow rate from well No. 2 was 3.7 tons/day. There was an increase in oil recovery factor by 15%.

Example 4.

The terrigenous area, on which 10 production and 3 injection wells are located, has the following parameters:

• Residual recoverable reserves amount to 17,900 tons.

• The coefficient of fragmentation for the production area of the deposit is 2.9

• 10 production wells in operation

• The current average reservoir pressure at production wells is 90 atm. (initial pressure - 170 atm.).

• Average porosity - 0.26

• Reservoir layers are distinguished, separated by an impermeable clayey or clayey low-permeability bridge. At the same time, the absolute permeability of productive layers differs by 1.2 times.

We selected production well No. 5, operating with a current flow rate of 0.3 t/day and a water cut of 98.5% (with an average flow rate for the area of 2.9 t/day). At the same time, production wells No. 2, 3, 4 operate within a radius of up to 800 m with an average oil flow rate of 4.0 tons per day and a volume of withdrawn liquid of 150 m ³ / day.

After transferring production well No. 5 to injection, injection was carried out with the following operating modes: 300 m ³ /day for 1 month, 300 m ³ /day for 2 months, 300 m ³ /day for 2 months, 300 m ³ /day for 6 months , 300 m ³ /day for 5 months, 300 m ³ /day for 4 months, 375 m ³ /day for 3 months, 450 m ³ /day for 2 months, 450 m ³ /day for 1 month. As a result, the following results were obtained:

The average reservoir pressure rose to 170 atm (+89%).

The average oil flow rate for wells Nos. 2,3,4 was 8.9 tons/day. There was an increase in oil recovery factor by 55%.

Claims (1)

A method for developing an oil deposit discovered by injection wells and at least two production wells, including pumping a working agent through injection wells and withdrawing fluid through production wells, characterized in that the residual recoverable oil reserves of the deposit area and the compartmentalization coefficient of the production facility are determined at a late stage of development select a deposit area with residual recoverable oil reserves of at least 3000 tons, with a compartmentalization coefficient for the production section of the deposit of more than 1.25 in at least one well, the current average reservoir pressure is less than the initial reservoir pressure on the deposit, the average porosity of productive sediments in wells is from 0.12 up to 0.26, in the deposit area, a production well is selected with a current flow rate lower than the average flow rate of the production wells of the selected area, the selected production well is transferred to an injection well, provided that there is at least one production well of the operating stock within a radius of 800 m from the selected production well, injection is carried out into selected well of the working agent as follows: in an amount of 40-200% of the volume of withdrawn liquid for 1 month, then in an amount of 60-200% of the volume of withdrawn liquid for 2 months, then in an amount of 80-200% of the volume of withdrawn liquid in for 2 months, then in an amount of 100-200% of the volume of fluid taken for 6 months, then in an amount of 120-200% of the volume of fluid taken for 5 months, then in an amount of 140-200% of the volume of fluid taken for 4 months, then in the amount of 160-250% of the volume of fluid taken for 3 months, then in the amount of 180-300% of the volume of fluid taken for 2 months, then in the amount of 200-300% of the volume of fluid taken for 1 month.