RU2528185C1 - Control method of oil pool development - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: method includes allocation of a pool area with wells intercoupled hydrodynamically, extraction of the product from producers with production rate analysis, injection of a displacement agent to injectors with definition of well interference contours and correction of the production rate for the producers. According to the invention production rate analysis and injection of a displacement agent to injectors is made on the basis of detected intercoupling with the respective injectors against their total production rate at actual operation at the allocated areas using archive databases from 1 year up to 20 years and current data for the whole optimisation period with increment of 1-3 months. By production rate control in the producers the volume of injection to the injectors is changed and redistributed considering impact of the respective producers and injectors. At that the total volume of injection is changed not more than per 10%. Regulation of the extraction modes from the producers includes increase in product extraction from wells with maintained or insignificantly increased water cut and reduction of extraction up to complete stoppage with fast product watering out. At that remaining reserves are worked out using the producing well stock with increase in total flow rate and reduction of total water cut of the product, and liquid movement flows are redistributed till the remaining reserves are worked out.

EFFECT: expanding application scope of the invention for different conditions and operation modes for injectors and producers as well as reducing material costs, water cut of the extracted product and increasing oil recovery factor.

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Description

The invention relates to the oil industry, in particular to methods for regulating the development of oil deposits, and can be used for automated selection of operating modes of the existing fund of injection wells of an oil field water flooding system by redistributing the volumes of injected agent into the reservoir and optimizing production selection modes at production wells to reduce water cut and increased oil production.

There is a method of developing an oil field in a monolithic formation (patent RU No. 2386798, IPC EV 43/20, publ. 04/20/2010). This method includes drilling wells, monitoring the energy state of each well, pumping water into injection wells, and extracting oil from production wells. According to the invention, the value of reservoir pressure for each production well corresponding to the planned oil production for this well is calculated in accordance with the analytical dependence. Then, the effective volume of water injection is determined, which ensures the displacement of fluid from the calculated production well in accordance with the analytical dependence. Water is injected into each injection well in a volume equal to the sum of the effective injection volumes attributable to production wells located in the area of impact of this injection well. At the same time, the intensity of current fluid withdrawals from production wells is stopped or reduced, or the amount of water accumulated during oil extraction from production wells is compensated for by the equal volume of water pumped into injection wells.

The disadvantage of this method is that when distributing the energy state of each well, there is no accounting for the interaction of neighboring injection and production wells that are part of the development system of the production facility, and possible hydrodynamic relationships between them. Also, there is no accounting for the geological and technological measures carried out at the site, which change the hydrodynamic interactions between wells.

Closest to the proposed one is a method for regulating the development of an oil deposit (patent RU No. 2328592, IPC EV 43/16, publ. 10.07.2008). The known method provides an increase in the efficiency of oil reserves. The method includes taking oil from production wells, injecting water into injection wells, maintaining bottomhole pressure at producing wells above oil saturation pressure with gas, and at injection wells below fracturing pressure, measuring technological modes of operation of the wells. According to the invention, using the geological and technological model of the field, liquid production flow rates are identical for all production wells, from a certain minimum production rate with a fixed increment in the production rate of the liquid to a pressure at the bottom of production wells equal to the pressure of oil saturation with gas. When at the bottom of any producing well the pressure of saturation of oil with gas is reached, its liquid rate is fixed and does not change during further drilling. Then, at each step of the sweep, the volume of water injection to maintain reservoir pressure as a whole for the development object is taken equal to the volume of produced fluid. Distribution by injection wells is performed in proportion to the injectivity of the wells. For each step of sweeping the flow rate of the production wells, the contours of the sections of the mutual influence of the wells of each development object of this field are determined. Distribute in time the flow rate of each well for oil until 100% water cut is achieved — the maximum possible oil recovery coefficient is achieved, which implements the optimal distribution of production and injection wells at the date of analysis.

The disadvantage of this method is that it does not take into account the various technical measures carried out on the reservoir for repair and maintenance of the RPM system and production, which change the hydrodynamic interactions between the wells. The selection of optimal volumes of water injection for injection wells is carried out in areas with the same production and injection modes, which significantly reduces the scope, while the implementation of the method requires a significant increase in the volume of water injection, which requires additional costs for pumping additional volumes of water.

The technical objectives of the invention are to expand the scope for various conditions of operation of injection and production wells, as well as reducing material costs, reducing water cut of produced products and increasing oil recovery factor (CIN) by selecting the optimal operating modes of injection wells included in the waterflooding system the entire oil reservoir or a single section, and the redistribution of product selection from production wells while maintaining the coefficient of nsation of the volume of fluid injected into the reservoir to the products extracted from it.

Technical problems are solved by the method of regulating the development of an oil reservoir, including the allocation of a reservoir with hydrodynamically connected wells, the selection of products from production wells, injection of the displacing agent into the injection wells, determining the contours of the mutual influence of the wells and adjusting the modes of injection of the displacing agent into the injection wells without significantly increasing the volume of injection from redistribution of product selection between producing wells.

What is new is that the analysis of production flow rates and displacement agent injection into injection wells is carried out on the basis of the identified relationships between injection wells and the corresponding production wells according to their total production rate during actual operation in the selected areas using historical databases from one to 20 years in increments 1-3 months and current data during the optimization work, and the flow rates from production wells are adjusted by changing the volumes and redistributing the injection into non-producing wells, taking into account the interaction of the corresponding production and injection wells, the total injection volume being changed by no more than 10%, after which the production modes are selected from production wells, including increasing production selection from wells with persistent or slightly increasing water cut and reducing production up to complete shutdown from wells with quickly flooded products, while the residual reserves are generated using the existing well stock with an increase in mmar flow rate and reduce the total water cut of the product, and the fluid flows redistribute to the development of residual oil reserves.

Figure 1 (a, b) shows the production wells 1, 2, 3 and injection wells 4, 5, 6, 7 with a schematic representation of the flow lines between them, the histograms show the interaction factors of these wells. Figure 1 shows two time sections: a) before optimization, b) after optimization.

Figure 2 shows a graph of the total oil production rate at producing wells 1, 2, 3 (Fig. 1) as a result of various optimization measures at injection wells 4, 5, 6, 7 (Fig. 1), as a result of which it was possible to increase the production rate oil and reduce water cut (a graph of changes which is shown in figure 3), without increasing the volume of injected fluid.

The method of developing an oil deposit was carried out with the selection of the optimal operating modes of the existing stock of injection wells 4, 5, 6, 7 (Fig. 1) by analyzing the waterflooding system both of historical data on the development of the field and of the ongoing optimization work and evaluation of the effectiveness of the obtained operating modes of these injection wells. As a result, they automatically select the optimal methods for injection rates of oil wells 4, 5, 6, 7 that are optimal in terms of oil flow rates and volumes of injection of the working agent, which allow reducing or maintaining the water cut of the produced product due to redistribution of fluid flow in the formation (Fig. 3) and increase the oil flow rate (figure 2) as a whole for the reservoir or a single site. At the same time, the total injection volume remains almost unchanged (increases or decreases by no more than 10%). To select the optimal methods of injection modes, the necessary information is initially gathered together from the available databases: operating modes of wells 1-7, production and injection volumes from wells 1-7. Based on the information collected, the dependencies of the production volumes of production wells 1-3 are calculated on the operating modes of injection wells 4-7, and the interaction factors are determined. For a detailed analysis at the last time interval, it is necessary to minimize the step of changing the studied parameters. For this, depending on the amount of information and the required accuracy, the last time of the development history (from a year to 20 years) is analyzed with a maximum allowable step of 1-3 months. According to the results of dependency calculations, dynamic relationships between injection 4-7 and reacting producing 1-3 wells are revealed. By changing the injection regimes, the optimum injection volumes for injection wells are automatically selected, at which the specified conditions are met. In this case, the specified conditions may be a decrease or maintenance at the current level of the total water cut of the produced products and / or an increase in oil production. After selecting the operating modes of injection wells, the optimization of operating modes at production wells is carried out. Due to the redistribution of volumes of selected products, the optimal operating mode for each producing well is determined. Optimization is carried out using automated software systems. A positive result of the proposed measures is achieved through the redistribution of fluid flows within the reservoir and the development of residual oil reserves.

An example of a specific implementation of this method of developing an oil deposit in the area of Berezovskaya area of the Romashkinskoye field.

Figure 1 (a, b) shows a waterflooding scheme of a selected section of a field in which the found optimal method is applied as a result of analysis of historical data in the production and injection system and finding the relationships between wells 1-7. To obtain optimal injection modes at injection wells, it is necessary to carry out a number of technical and computational measures. A section of the reservoir was selected where, prior to optimization, production wells 1, 2, 3 had an impact of injection 5, 6, 7 with an injection volume of 5000 m ³ per month. In order to increase the total oil production rate for wells 1, 2, and 3 (it was 65 tons per day) and at the same time not to increase water cut from 63% in this section, we analyzed the interference of wells over 12 years in increments of one month (from 01.01 .2000 to 01.01.2012). As a result, the interaction coefficients between each wells 1-3 and 4-7 were determined (operating modes of wells 1-7, production and injection volumes from wells 1-7) and the best possible methods of injection modes at injection wells 4-7 were selected. The mutual interference coefficients of wells 1-3 and 4-7 were determined by known methods (Lisin A.S. Calculation of the mutual interference coefficients of the wells by the grid method.) From the necessary information originally collected together from the available databases: well operation modes 1-7, production volumes and injections from wells 1-7, taking into account the existing geological and hydrodynamic model of the oil reservoir adapted to the development history and pressures (response time, bottomhole and reservoir pressures, compensation for production by injection). Based on the foregoing, the response time for this section is determined by both technical and calculated hydrodynamic methods, and it ranges from 30 to 90 days. Based on the information collected, the dependencies of the production flow rates of the producing wells on the operating modes of the injection wells were calculated taking into account the interaction factors for the selection of optimal methods for injection into wells 4-7.

Before changes in the injection regimes at wells 4, 5, 6, 7, the optimized options for the operation of injection wells were tested in the predictive calculations of the geological and hydrodynamic model. As a result of hydrodynamic calculations, the quality control of the proposed activities is carried out, economic efficiency is evaluated. Also, updated information on the results of hydrodynamic modeling can be used as input to refine optimization calculations.

The graphs show the total flow rate (Fig. 2) of the extracted product and its total water cut (Fig. 3), which shows the curves I, II, III - the corresponding changes in the total production (Fig. 2) and water cut of the product (Fig. 3) for various modes of production from wells 1-3 and injection into wells 4-7 of a displacing agent (water). I is a curve of the flow rate change (FIG. 2) and the water cut of the production (FIG. 3) during the development of this section without changing the injection regimes into wells 4-7 (FIG. 1); II is the calculated curve of the change in flow rate (figure 2) and water cut of the product (figure 3) during the development of the selected area with a change in injection regimes into wells 4-7 (figure 1) according to the closest analogue; III is a graph of the change in flow rate (Fig. 2) and water cut of the product (Fig. 3) with a change in injection regimes and redistribution into wells 4-7 (Fig. 1) without practical changes in the total volumes (not more than 10%) and selection wells 1-3 (figure 1), taking into account the coefficients of mutual influence; IV is a graph of changes in the actual production rate (figure 2) and water cut of the product (figure 3) during the development of the site, taking into account all the optimization recommendations.

Figure 2 shows the total oil production in the area for different optimization methods of injection for four months with forecasts for the next two months. If these optimal methods are not applied, then the oil production rate will decrease (curve I) and within the next three months it will decrease from 64 to 56 tons / day; with the first method chosen, the oil production rate (curve II) will be maintained at 71 tons / day. When using the optimization method described in the closest analogue, the flow rate will first increase, and then will decrease from 71 to 65 tons / day. Changes in the total oil production rate in the area are shown by curve III: after optimization work on injection wells, the production rate increased from 64.4 to 71.4 tons / day with lower injection costs.

Figure 3 shows that when choosing the optimal injection modes, on the contrary, the water cut decreases (curve II) from 61 to 59%, but does not increase (curve I) from 61 to 63%, if you do not use the optimal methods. Curve III shows the reduction in water cut from 63 to 60.5% when choosing the optimization mode for injection at injection wells 4, 5, 6, 7 and intensification of selection at production wells 1, 2, 3 (Fig. 1). Curve IV (figure 3) shows the result of reducing water cut due to the practical application of optimization actions.

According to the found optimal mode (see curve III in FIGS. 2 and 3), the injection volume in wells 5, 6, and 7 was changed in the section (Fig. 1b) to increase oil production. In well 5, the injection volume was reduced from 1400 to 1000 m ³ / month The injection volume at well 6 remained unchanged at the level of 2000 m ³ / month, while at injection 7, injection was increased from 1600 to 2000 m ³ / month and well 4, which was previously put into cyclic mode, with an injection volume of 600 m ³ / month, was included. Moreover, the total total volume of injected and produced fluid remains within the specified limits of 5000-5500 m ³ / month.

After selecting the operating modes of the injection wells 4, 5, 6, 7 (Fig.1b), optimization of the operating modes in production wells is carried out. Due to the redistribution of the volumes of selected products, determine the optimal mode of operation for each producing well 1, 2, 3 (fig.1b). Optimization is carried out using automated software systems. With their help, inefficient production wells are determined. These include highly flooded or rapidly watered wells. At these wells, production selection is reduced to a complete stop. The non-selected volume of production is compensated by increasing production at other wells so that the coefficient of compensation for production by injection remains at the current level.

Preliminary predictive calculations showed that, based on the operating modes of the injection wells determined at the previous stage, faster watering of well 1 (Fig. 1a) is observed compared to well 2. For a more uniform production of reserves, the volumes of production between the wells were redistributed. To do this, in well 1 (Fig. 1b), fluid withdrawal was reduced by 30% (from 26 to 18 m ³ / month), and in well 2 (Fig. 1b), the decrease in production in well 1 (Fig. 1a) was compensated by an increase from 8 up to 16 m ³ / day. Under these conditions, the development of reserves was carried out more evenly with a gradual increase in water cut in the selected wells. When redistributing the volumes of produced fluid between the wells by 10 and 50%, the uniformity of the development of reserves was not achieved due to the rapid watering of one or another well.

For well 3 (figb), it was decided to leave the previous modes.

As a result, after the measures, the actual total oil production in the area increased from 64.4 to 72 tons / day (see curve IV in FIG. 2), the total water cut decreased from 63 to 60.3% (see curve IV in FIG. 3), which practically corresponds to the calculated data.

The number of injection and production wells may be different. It is determined by their mutual influence. An analysis of changes in mutual influences for a site with a large number of wells is carried out automatically using computing tools.

The proposed method is essentially a physical method of increasing oil recovery and can reduce the water cut of producing wells by 5-10%, and increase oil production by 5-10% without additional costs for re-equipping wells and increasing injection volumes. Moreover, the use of the method for regulating the development of oil deposits is effective in areas with different operating conditions.

Claims (1)

A method for regulating the development of an oil deposit, including the allocation of a field site with hydrodynamically connected wells, the selection of products from production wells with analysis by production rate, injection of displacing agent into injection wells with determination of the contours of the mutual influence of wells and adjustment of production rates of production wells, characterized in that the analysis is based on production rates wells and injection of displacing agent into injection wells is carried out on the basis of the identified relationships of injection wells with the corresponding production wells according to their total production rate during actual operation in selected areas using historical databases from a year to 20 years in increments of 1-3 months and current data during optimization work, and production rates from production wells are adjusted by changing volumes and redistributing injection into injection wells, taking into account the mutual influence of the corresponding production and injection wells, and the total injection volume is changed by no more than 10%, after which the extraction methods from production wells, including increasing production selection from wells with persistent or slightly increasing water cut and reducing production up to a complete shutdown from wells with quickly waterlogged production, while residual reserves are generated using the existing well stock with an increase in total production rate and a decrease in total water cut products, and the fluid flows redistribute to the development of residual oil reserves.

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