RU2827224C1 - Method of increasing oil recovery at facilities with formed formation pressure maintenance system - Google Patents

Abstract

FIELD: oil industry.

SUBSTANCE: invention relates to the oil industry, in particular to the field of development of oil deposits at a later stage of development, and can be used in development of oil deposits with terrigenous reservoir, separated by clay impermeable or clay-covered low-permeable bridge. Method of increasing oil recovery at facilities with a formed formation pressure maintenance system, opened by injection wells and at least two production wells, includes determining filtration-capacitive characteristics of productive formations, pumping of working agent through injection wells and extraction of liquid through production wells. Additionally, residual recoverable oil reserves are determined for the deposit section and the compartmentalization factor for the production facility; at the later stage of development, the deposit section drilled according to the design grid of wells is selected, where withdrawals are carried out by means of mechanized production from production wells with residual recoverable oil reserves in the deposit section of not less than 3,000 t with extraction of recoverable reserves of not more than 90%, average value of the compartmentalization factor for the production section of the deposit is not less than 1.25, the average formation pressure on the producers is less than 0.7 of the initial formation pressure in the section of the deposit, the average porosity of the productive deposits for the wells is from 0.12 to 0.26, with absolute permeability of productive interlayers, differing by more than 1.2 times, type of injected water – water of surface water sources with mineralization from 0.2 to 285 g/l, bottomhole pressure in injection wells is increased by at least 1.2 times from the average value of bottomhole pressure for the last month until formation pressure in the deposit area increases by 20 to 80% for 1-6 months, but not more than by 20% from initial formation pressure at deposit section, then, depression is increased in the bottomhole zone of producing wells by reducing bottomhole pressure to 40-50 atm for terrigenous Devonian and to 20-30 atm for terrigenous Carboniferous. Residual oil pillars, lenses, dead-end and stagnant zones, low-permeability interlayers are involved in development in non-uniform flooded formations by bringing the site into the above-mentioned operating mode, oil recovery is increased.

EFFECT: this method is a powerful stimulus for intensification of oil production and increase in oil recovery.

1 cl, 3 ex

Description

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

A method is known for the systematic cyclic development of an oil deposit at a late stage (patent RU No. 2209947, IPC E21B 43/16, published on 10.08.2003), including the injection of a displacing agent through one or more injection wells, the extraction of oil through one or more production wells, the analysis of geological and production data on the operation of each of the wells taking into account the entire history of the development of this deposit, the selection from the development history of spontaneous - unplanned changes in the hydrodynamic mode of operation of all wells and the response of the deposit to these spontaneous changes in the hydrodynamic mode by changes in the performance indicators of the production wells, the selection of zones of residual oil reserves based on the response of the deposit, the determination of the amount of residual oil reserves based on the parameters of the received response and targeted regulation of the development system in the selected response zones taking into account the received response results. In the selected zones, additional injection and/or production wells are drilled, and in the selected zones, the predominant primary directions of filtration flows of the displacing agent into the deposits are identified, after which the filtration flows are given new directions.

The disadvantages of this method are the high cost of its implementation, due to the fact that additional injection and/or production wells are drilled in the allocated zones, the low efficiency of the method due to the complexity of its implementation, and the lack of targeted alignment of the injectivity profiles.

A method for non-stationary development of low-permeability reservoirs is also known (RU patent No. 2716759, IPC E21B 43/20, published on 16.03.2020), which involves drilling horizontal wells, with the horizontal wellbores located with an azimuth offset of more than 10 degrees relative to the direction of the maximum horizontal stress in the formation. Multi-stage hydraulic fracturing of the formation is carried out in the wells. Production is carried out in at least two wells, at least one of the above-mentioned wells is used as an injection well by pumping in a working fluid. The working fluid is pumped into at least one injection well with a pressure exceeding the hydraulic fracturing pressure of the formation. If fluid breaks through from the injection well along the auto-HF cracks into at least one well in production mode, the production well is stopped. The working fluid is pumped into the injection well until the volume of the working fluid pumped into the injection well exceeds the total volume of fluid extracted from the production well at the previous stages, the injection well is stopped, and production is carried out. The technical result consists in increasing the efficiency of developing low-permeability reservoirs and simplifying the production process.

The disadvantage of this method is the high cost of drilling horizontal wells and possible technological limitations on the possibility of increasing the injection pressure.

Also known is a method for developing an oil deposit (patent RU No. 2336413, IPC E21B 43/20, published 20.10.2008), including determining the filtration-capacity characteristics of a productive formation, establishing the dependence of the value of bottomhole injection pressure and formation pressure on the filtration-capacity characteristics, determining the intervals of optimal injection pressures and formation pressures, pumping a working agent through injection wells and withdrawing products through production wells in filtration modes corresponding to optimal values of injection pressure and formation pressures between the injection and withdrawal zones, wherein each injection and production well is equipped with bottomhole pressure sensors, at least once a day the bottomhole pressures in all wells are measured and the formation pressure near the wells is calculated, stopping the injection and withdrawal and/or changing the operating modes wells maintain optimal reservoir pressure in the formation from the point of view of maximum oil recovery, while planning well shutdowns for repairs and simultaneously carrying out measures to maintain reservoir pressure in the development area regardless of its change during the well repair process.

The known method is reproducible on a small area and for a short time due to the high material costs of downhole sensors with telemetry to the surface and the great organizational difficulties caused by the daily removal and processing of information from the sensors, which is not yet automated or computerized. With such analysis and measures, the development of the deposit remains at a low level, the water cut of the production wells occurs at an accelerated rate compared to the achieved oil recovery.

The closest method is the oil field development method (RU patent No. 2540718, IPC E21B 43/16, published 10.02.2015), including determining the filtration-capacity characteristics of productive formations, establishing the dependence of the value of bottomhole injection pressure and formation pressure on the filtration-capacity characteristics, determining the intervals of optimal injection pressures and formation pressures, pumping a working agent through injection wells and withdrawing products through production wells in filtration modes corresponding to optimal values of injection pressure and formation pressures between injection and withdrawal zones, stopping injection and withdrawal and/or changing the operating modes of wells, maintaining optimal formation pressure in the formation from the point of view of maximum oil recovery, and equipping injection wells with individual means for measuring fluid flow and equipping production wells with flow rate sensors loads on pumping equipment, archiving and averaging up to daily values of sensor readings received via the telemetry system in real time, on the field map with the coordinates of the well bottoms, a volumetric section of the field with at least 6 wells within one or more productive formations is outlined with the inclusion of production and injection wells in the outline, for each injection well, data is measured once every 2 hours and averaged once a day, every 40 days a graph of the change in flow rate for the injection well depending on the operating time of the well is plotted, for production wells, data is measured once every 2 hours and averaged once a day, every 40 days a graph of the change in load on the pumping equipment depending on the operating time of the well is plotted, compared by superimposing 2 graphs for injection and production wells, the similarity of the amplitudes in terms of oscillation height, the distance of the points of maximum flow parameters and the operating time of production wells is determined over the same time interval, with full if the graph peaks coincide, a conclusion is made about the direct influence of the injection well on the production well; if there is a complete mismatch, a conclusion is made about the influence over a period of time; if there is a partial coincidence, a conclusion is made about the influence over a part of a period of time; if there are no peaks of the production well, depending on the peaks of the fluctuations in the operating parameters of the injection well, a conclusion is made about the absence of influence of the injection wells on the production well; the coefficient of mutual influence is calculated.

The disadvantage of the method is the rather labor-intensive sequence of implementation of the method, including analysis and construction of graphs, as a consequence, the complexity of field development, as well as insufficiently high oil recovery.

The technical challenge is to increase oil recovery by changing the displacement front and involving additional oil reserves in development.

The technical problem is solved by a method of increasing oil recovery at sites with a formed reservoir pressure maintenance system, opened by injection wells and at least two production wells, including determining the filtration and capacity characteristics of productive formations, pumping a working agent through injection wells and withdrawing liquid through production wells.

What is new is that the residual recoverable oil reserves for the deposit section and the compartmentalization coefficient for the production facility are additionally determined; at a late stage of development, a deposit section drilled according to the design well grid is selected, where the extraction is carried out by means of mechanized production from production wells with residual recoverable oil reserves for the deposit section of at least 3,000 tons with the extraction of recoverable reserves of no more than 90%, an average compartmentalization coefficient for the production section of the deposit of more than 1.25, an average reservoir pressure in production wells of less than 0.7 of the initial reservoir pressure in the deposit section, an average porosity of productive deposits in wells from 0.12 to 0.26, with an absolute permeability of productive interlayers differing by more than 1.2 times, the type of injected water - water from surface water sources with a mineralization of 0.2 g / l to 285 g/l, increase the bottomhole pressure in injection wells by at least 1.2 times from the average value of bottomhole pressure for the last month until the reservoir pressure in the deposit area increases by 20% to 80% over 1–6 months, but not more than 20% from the initial reservoir pressure in the deposit area, then increase the depression in the bottomhole zone of production wells by reducing the bottomhole pressure to 40–50 atm for terrigenous Devonian and to 20–30 atm for terrigenous Carboniferous.

The essence of the proposed method is as follows.

At a late stage of development, effective flooding plays a major role in order to displace residual oil reserves. As a result of pumping a large volume of water, washed zones are formed in more permeable interlayers, while less permeable zones that contain a larger volume of oil remain uncovered. Flooding, due to the viscosity instability of the displacement process, leads to the formation of oil pillars bypassed by water. Part of the mobile reserves of hydrocarbon raw materials remains unextracted from the formation environments.

The deposit area is drilled according to the design grid by injection wells and at least two production wells. The filtration and capacity characteristics of the productive formations, the values of the bottomhole injection pressure and formation pressure are determined. The deposit is exploited in a natural mode, selections are carried out by means of mechanized extraction from production wells, the working (displacing) agent is injected through injection wells. Within the section, the reservoir layers are separated by a clayey impermeable or clayey low-permeability isolator, the productive reservoir is composed of terrigenous rocks, mainly polymictic sandstones of the graywacke type.

When implementing the proposed method, the residual recoverable oil reserves for the deposit area and the dissection coefficient for the production facility are additionally determined. At a late stage of development, a section of the deposit being developed is selected, drilled according to the design well grid (or with subsequent compaction by additional drilling). The criteria for selecting a deposit area are the following characteristics: residual recoverable oil reserves for the deposit area - at least 3,000 tons with the selection of recoverable reserves of no more than 90%, the dissection coefficient for the production area of the deposit is more than 1.25, the presence of at least two wells of the production stock in operation on the deposit area, the average reservoir pressure in the production wells is less than 0.7 of the initial reservoir pressure on the deposit area, the average porosity of productive deposits by wells is from 0.12 to 0.26, the absolute permeability of productive interlayers differs by more than 1.2 times.

At the initial stage of development, the reservoir section is exploited in a natural mode until the reservoir energy level decreases (in practice, usually to values of 0.4-0.9 of the initial reservoir pressure), followed by a transition to the artificial reservoir pressure maintenance mode with the organization of partial compensation for fluid withdrawals by injecting a working agent. Low-mineralized water from surface water sources (river network, underflow water intakes, etc.), specially extracted formation water, and bottom water from oil treatment facilities are used as a working agent for displacement. The mineralization of the injected agent is from 0.2 g/l to 285 g/l. Subsequent compaction of the well grid beyond that provided for by the project is allowed.

The bottomhole pressure in injection wells is increased by at least 1.2 times the average bottomhole pressure value for the last month until the reservoir pressure in the deposit area is increased by 20% to 80% over 1-6 months, but not more than 20% of the initial reservoir pressure in the deposit area. That is, the bottomhole pressure in injection wells is increased in the selected deposit area, and the volume of displacing agent injection is increased accordingly. This mode of water injection into multi-layer objects leads to an expansion of the injectivity interval of the operating layers and the involvement of new, previously uncovered zones in development.

Next, the depression in the bottomhole zone of the production wells is increased by reducing the bottomhole pressure to 40-50 atm for terrigenous Devonian and to 20-30 atm for terrigenous Carboniferous. Accordingly, this leads to an increase in the selection of the produced liquid (oil).

By bringing the deposit area into the above-mentioned operating mode in heterogeneous watered formations, residual oil pillars, lenses, dead-end and stagnant zones, low-probability interlayers are involved in development, and oil recovery increases. This method is a powerful incentive for intensifying oil production and increasing oil recovery.

Example 1.

The Devonian terrigenous section is represented by one injection and two production wells with residual reserves of 3000 tons (with 90% recoverable reserves), and a compartmentalization factor of 1.25. The average reservoir pressure is 120 atm (with an initial pressure of 175 atm), and the average porosity is 0.12. The absolute permeability of the productive interlayers differs by 1.3 times, and water with a mineralization of 0.2 g/l is injected. The bottomhole pressure at the injection well was increased by 1.2 times (from the average bottomhole pressure for the last month of 250 atm to 300 atm) by increasing the reservoir pressure by 20% over 6 months (by increasing the injection pressure and, accordingly, the injection volume). The reservoir pressure increases from 120 atm to 144 atm. After this, the depression was increased at two production wells by reducing the bottomhole pressure at the production wells to 40 atm (by increasing the extraction of the extracted liquid). As a result, the oil flow rate increased by 4 tons/day.

Example 2.

The terrigenous carboniferous section is represented by one injection and four production wells with residual reserves of 10,500 tons (with 50% recoverable reserves), and a compartmentalization factor of 1.5. The average reservoir pressure is 105 atm (with an initial pressure of 175 atm), and the average porosity is 0.26. At the same time, the absolute permeability of productive interlayers differs by 1.4 times, and water with a mineralization of 285 g/l is injected. The bottomhole pressure at the injection well was increased by 1.5 times (from the average bottomhole pressure for the last month of 240 atm to 360 atm) by increasing the reservoir pressure by 80% over 1 month (by increasing the injection pressure and, accordingly, the injection volume), and the reservoir pressure increased from 105 atm to 189 atm. After this, the depression was increased at two production wells by reducing the bottomhole pressure at the production wells to 30 atm (by increasing the extraction of the extracted liquid). In other examples of practical application for terrigenous carbon, the bottomhole pressure was increased to 20 and 25 atm. As a result, the oil flow rate increased by 7 tons/day.

Example 3.

The Devonian terrigenous section is represented by one injection and three production wells with residual reserves of 7,500 tons (with recoverable reserves recovery of 73%) and a compartmentalization factor of 1.4. The average reservoir pressure is 140 atm (with an initial pressure of 175 atm), and the average porosity is 0.20. The absolute permeability of productive interlayers differs by 1.25 times, and water with a mineralization of 0.17 g/l is injected. The bottomhole pressure in the injection well was increased by 1.3 times (from 250 atm to 325 atm) by increasing the reservoir pressure by 50% over 3 months (by increasing the injection pressure and, accordingly, the injection volume), and the reservoir pressure increased from 140 atm to 210 atm. After this, the depression was increased at the production well by reducing the bottomhole pressure at the production wells to 50 atm (by increasing the extraction of the extracted liquid). In other examples of practical application for the terrigenous Devonian, the bottomhole pressure was increased to 45 atm. As a result, the oil flow rate increased by 3.5 tons/day.

Claims (1)

A method for increasing oil recovery at facilities with a formed reservoir pressure maintenance system, penetrated by injection wells and at least two production wells, including determining the filtration and capacity characteristics of productive formations, pumping a working agent through injection wells and withdrawing liquid through production wells, characterized in that the residual recoverable oil reserves for a section of the deposit and the compartmentalization coefficient for the production facility are additionally determined, at a late stage of development, a section of the deposit drilled according to the design well grid is selected, where the selections are carried out by means of mechanized extraction from production wells with residual recoverable oil reserves for a section of the deposit of at least 3,000 tons with the selection of recoverable reserves of no more than 90%, an average compartmentalization coefficient for the production section of the deposit of at least 1.25, an average reservoir pressure in the production wells of less than 0.7 of the initial reservoir pressure in the section of the deposit, an average porosity of productive deposits in wells from 0.12 to 0.26, with absolute permeability of productive layers differing by more than 1.2 times, the type of injected water - water from surface water sources with mineralization from 0.2 to 285 g / l, they increase the bottomhole pressure in injection wells by at least 1.2 times from the average value of the bottomhole pressure for the last month until the reservoir pressure in the deposit area increases by 20 to 80% over 1-6 months, but not more than 20% of the initial reservoir pressure in the deposit area, then they increase the depression in the bottomhole zone of production wells by reducing the bottomhole pressure to a value of 40-50 atm for terrigenous Devonian and to 20-30 atm for terrigenous Carboniferous.