RU2692369C1 - Method of selecting deposit development system - Google Patents

Abstract

FIELD: mining.SUBSTANCE: claimed invention relates to complex systems and methods of designing deposits and can be used to solve the problem of determining the optimal method of placing wells at a deposit. Method includes formation of a set of initial geological, topographic, geophysical data characterizing the formation, determination of a set of output variable parameters characterizing the development system, wherein for each type of the development system and each variable parameter of the development system, a number of steps are taken. Said steps include: generating a development system element template; determination of yield of all wells included in formed template of development system element, for this purpose wells with different type of completion, included into template, are represented in the form of point sources. Geometrical parameters of current tubes are determined based on the obtained yields of all point sources. Two-phase transient filtration of incompressible liquids is calculated along each current tube, resulting in distribution of water and oil saturation along each current tube, as well as dynamics of oil production and water production / pumping for all point sources. Solutions are summed up on all sources corresponding to each well, as a result of which a stationary two-phase solution is obtained for well flow rates. Single-phase flow rates of all point sources simulating the wells in the development system element are calculated using the piezoelectric conductivity equation by the quasi-stationary approximation method, after which a non-stationary single-phase solution for well flow rates is obtained, which characterizes dependence of well flow rate on time, by summation of single-phase yields on all point sources corresponding to wells. Single-phase non-stationary solution and stationary two-phase solution are combined, as a result, dynamics of oil and water production, water pumping for all wells is obtained. Flow rates of wells are determined based on their location on thickness map, after which the wells ranging from large thicknesses to smaller ones are performed in accordance with geometrical parameters of the template element of the development system and based on the comparison, wells having a positive value of pure discounted income (NPV) are selected. Total well profiles, oil and injection are calculated by selected wells. Dynamics of gas production is determined from obtained profiles of oil production based on gas content. Total NPV is determined from total oil production profiles. Said steps are repeated for each type of development system and for each other value of the parameter to be sorted in one development system. Optimum system of deposit development is selected based on maximum value of complex optimization target parameter.EFFECT: technical result consists in provision of potential possibility of increasing oil recovery of formations, which is manifested in increase of oil recovery factor (ORF) due to preliminary determination of optimal version of arrangement of wells at deposit.4 cl, 22 dwg, 1 tbl

Description

The technical field to which the invention relates.

The invention relates to integrated systems and methods for the design of field facilities. The invention can be used to solve the problem of determining the optimal method of well placement in the field, taking into account the development system, the density of the grid wells, the strain grid, profitable areas; well injection rate, restrictions on the rate of oil recovery at the maximum production, the values of the well control parameters.

The level of technology

The prior art method of developing fields using a nine-point system of areal distribution of wells (patent US 3402768 A). The method allows to increase oil recovery due to the implementation of a sequence of actions, including the injection of water into certain injection wells, the completion of individual wells, the conversion of individual production wells into injection wells.

However, this method only describes the use of a specific areal well distribution system for the implementation of secondary production of petroleum products, while there is no possibility of choosing this system with the construction of the most efficient areal well distribution.

A known system and method for automated planning of well construction and drainage sites (publication EP 2150683). The method includes determining the location of surface and underground production and injection wells in the field, from several independent sets of wells placed on a static model of the reservoir according to a specific algorithm. The most promising sets of wells are selected based on the results of dynamic flow modeling using the cost function, for example, maximizing net present value (NPV).

The process is characterized by the use of a complex hierarchical algorithm, which is based on an increase in computational intensity with a decrease in the sample of wells being processed. In addition, this technical solution uses a stage associated with the calculation of hydrodynamic parameters on the simulator. This approach is quite justified, however, it leads to an increase in the duration of the calculations and, as a consequence, a decrease in the productivity of the method.

From the prior art a method for selecting a field development system based on the use of mathematical optimization methods is known / Khasanov M.M. et al. / 171163-MS, 2014 (prototype). Based on a dynamic field model using original optimization algorithms, key parameters of the development scheme are determined: horizontal well length, well location, control parameters that can improve the economic performance of the projected field — net discounted income (NPV) and oil recovery factor (KIN). The result of solving the problem for the lower detail model is the initial approximation for solving the optimization problem using the model of the next level of detail. The optimization task is divided into several smaller subtasks, where successively are determined: the optimal parameters of the development pattern (the five-point pattern described as an example), the optimal location of wells within one row to account for reservoir properties of the reservoir, as well as optimal control parameters. This makes it possible to significantly reduce the amount of computations for a full-scale field model.

However, this publication describes only the mathematical apparatus used in solving the design problem as a whole, and there is no detailed description of the sequence of actions that must be carried out to select the optimal field development system. Thus, this source of information does not reveal the essence of the algorithm for selecting a development system that satisfies a set of input characteristics that ensures the possibility of achieving high CIN and NPV. However, this source of information is the closest in essence to the claimed invention and is selected as a prototype.

DISCLOSURE OF INVENTION

The technical problem that the claimed invention is intended to solve is to overcome the drawbacks inherent in the analogs and the prototype by providing the possibility of choosing the option for the location of wells in the field when developing new assets of the development system before the development of the field begins. The main problem solved with the use of the claimed invention is reduced to enhanced oil recovery.

The technical result achieved with the use of the claimed invention is to provide the potential for enhanced oil recovery, resulting in an increase in the oil recovery factor (CIN), due to a preliminary determination of the optimal well location in the field. The sequence of actions aimed at determining such an optimal development system provides the possibility of correcting the work carried out during the field development even before the start of drilling. The result is achieved by simultaneously taking into account the original set of indicators - geological, topographic, geophysical, reflecting both the properties of the reservoir, planned for development, and the characteristics of the means and parameters of oil production, used with regard to this reservoir. It also provides the possibility of operative processing of heterogeneous data - geological, topographic, geophysical, with the formation at the output of an optimal project of area distribution of wells obtained as a result of processing a large array of possible options, each of which is characterized by a specific value of a complex target parameter (CIN or NPV). In addition, the claimed invention allows to increase system performance when solving the task by providing the possibility of splitting the problem being solved into smaller subtasks of smaller dimension, requiring much smaller software resources, as well as increasing the volume and variability of the data being processed in comparison with the known analogues (i.e. allows you to process more data with a result (product) in less time).

The problem is solved in that the method of selecting a field development system is the determination of the area location of wells, including

- formation of a set of initial geological, topographic, geophysical data characterizing the reservoir;

- determining the set of output variable parameters characterizing the development system, with the following steps for each of the types of the development system and each variable parameter of the development system being performed to ensure the well flow rate over time:

1) form a pattern of the development system element based on the algorithm for calculating the coordinates of the wells for the given development system parameters;

2) determine the flow rate of all wells included in the generated pattern of the development system element, for which wells with different types of completion included in the pattern are presented as point sources, then the flow rates of all point sources are specified as input data using downhole pressure solving the steady state filtration equation;

3) on the basis of the obtained flow rates of all point sources, the geometrical parameters of the current tubes are determined, while the beginning of the tubes is the point sources corresponding to the injection wells, and the point sources corresponding to the production wells are considered the end;

4) perform a calculation of two-phase unsteady filtration of incompressible liquids along each current tube, resulting in a distribution of water and oil saturation along each current tube, as well as the dynamics of oil production, water production / injection for all point sources;

от коэффициента извлечения нефти, где

- дебит жидкости в 5) carry out the summation of solutions for all sources corresponding to each well, resulting in a stationary two-phase solution for well flow rates, which is the displacement characteristic (water content dependence on oil recovery factor (KIN)) and

from oil recovery rate where

- liquid flow rate

initial moment of time;

6) perform the calculation of single-phase flow rates of all point sources that simulate wells in an element of a development system using the piezoconductivity equation using the method of quasistationary approximations, after which a non-stationary single-phase solution for flow rates, characterizing the dependence of flow rates on time, is obtained by summing single-phase flow rates for all point sources, appropriate wells;

7) according to the displacement characteristic obtained in step 5) and non-stationary single-phase well rates in step 6), a single-phase non-stationary solution and a stationary two-phase solution are combined, resulting in oil and water production dynamics, water injection for all wells in a fixed system element baseline formation thickness, which is a solution for an average well;

8) determine the flow rates of wells, based on their location on the thickness map, then the wells are ranked from large thicknesses to smaller ones according to the geometrical parameters of the development system element template, and based on the comparison, wells having a positive NPV value are distinguished;

9) for the selected wells perform the calculation of total profiles of oil production, fluid and injection;

10) determine the dynamics of gas production based on the obtained oil production profiles on the basis of gas content;

11) total NPV is determined by total profiles of oil production;

12) steps 1) -11) are repeated for each type of development system and for each other value of the parameter being sorted in one development system,

then, according to the maximum value of the complex target optimization parameter, the most optimal field development system is selected. As a complex target optimization parameter, use the value of total NPV or CIN or the profitability index PI or the value of the maximum NPV at the maximum CIN.

The selected development system is further recommended for subsequent use in a particular field, the initial data of which are taken as the initial data for the implementation of the method. As such initial data, use is made of a thickness map or one average value of the formation thickness, average formation permeability, average formation porosity, fluid parameters (PVT), namely the saturation pressure for oil, fluid viscosity, volume coefficients, densities, ranges of filtration-capacitance properties ( PES) of the reservoir, ranges of parameters of relative phase permeability (OFP), ranges of change of parameters of the development system. The output variable parameters of the development system use the type of development systems, the type of wells completed and design parameters, namely the development system density (S), α is the ratio of the number of producing wells to injection wells, the ratio of the distance between wells in row (a) to the distance between rows wells (b), the coefficient of stretching the pattern of the development system along a given direction.

When selecting wells with a positive NPV value, for each well:

- determine the capital costs, including the costs of dumping and engineering preparation of the bushes (filling the cluster pad, discharge lines, a platform for the foundation of the oil and gas field equipment, etc.), the cost of well construction, including the method of completion, the cost of equipment not included in the estimate construction sites (tubing, cables, pumps, etc.);

- determine the operating costs, including the cost of oil production, the cost of extracting fluid, the cost of pumping water, the cost of maintaining wells, the cost of maintaining the bushes;

- determine the income from the sale of oil:

- determine the mineral extraction tax

- determine the property tax

- determine the income tax

- determine the net cash flow

- determine the accumulated discounted flow (NPV),

then compare the obtained NPV with zero, and when exceeding 0, make a conclusion about the profitability of the well.

Description of the drawings

The invention is illustrated by the following images:

FIG. 1 shows a block diagram disclosing a sequence of actions in the implementation of the proposed method.

FIG. 2 shows the variants of field development systems taking into account the number of injection and production wells used as input parameters for the implementation of the proposed method (five, seven and nine point development systems).

FIG. 3 shows two options for a five-point system of development of fields with different density of the grid of wells, used as an input parameter for the implementation of the proposed method.

FIG. 4a and 4b show options for stretching the grid of wells, which are used as input parameters for the implementation of the proposed method.

FIG. 5 shows an example of the calculation of the IOPS.

FIG. 6 shows an example of the dependence of the coverage factor on the length of the current tubes when matching the functions.

FIG. 7 shows an example of the dependence of the coverage factor on the length of the tubes, determined from the statistics of lens sizes.

FIG. 8 shows the general scheme for determining the auto-fracturing.

FIG. 9 shows a scheme for determining the flow rate of an average well in a regular development system.

FIG. 10 shows an example of the calculation of current tubes for a five-point well pattern.

FIG. 11 shows the scheme for determining the optimal development system using the EMV parameter.

FIG. 12 shows the possible well pattern patterns for the example under consideration. Injection strokes are highlighted with small strokes, and extractive wells are marked with large ones.

FIG. 13 shows the changes in well displacement.

FIG. Figure 14 shows the changes in the type of completion of wells and the consideration of auto-fracturing at injection wells. NNS - directional wells, Hor. - horizontal well, MGRP - multi-stage hydraulic fracturing.

FIG. 15a shows changes in the density of the wellbore; FIG. 15b - changes in the a / b parameter at a fixed well grid density.

FIG. 16 shows the possible values of the complex parameter ƒ depending on the ratio a / b for the five best options.

FIG. 17 shows the recommended (a) and implemented (b) development systems for the example described.

The implementation of the invention

Below is a detailed description of the invention. The specialist it is clear that the following description of the implementation of the present invention is purely explanatory in nature and does not limit the scope of the claims stated in the claims.

The claimed technical solution can be implemented in the form of a program complex, with the help of which they provide a solution to the problem of choosing the optimal field development system, the use of which will increase the degree of oil recovery of the field. At the same time, the value of the complex target parameter — net discounted income (NPV) or CIN, or the values of the expected monetary value of EMV derived from them are used as the parameters achieved as a result of optimization.

To solve this problem, a careful analysis of possible options for a field development system is necessary, highlighting the most promising ones.

Solving such a problem is directly related to the use of a three-dimensional or two-dimensional field model, as well as finding a solution in a multidimensional space, which, given the need for analyzing uncertainties, implies a large amount of computation and computer time. Conceptually, the authors proposed a universal method for determining the optimal variant of an area well location based on the consistent use of field models with increasing granularity, ranging from analytical and semi-analytical to models based on two-dimensional thickness and permeability maps. In the transition to a more detailed model of the field, the optimal solution obtained on the basis of the previous step is used as an initial approximation. Thus, the concept of a hierarchical approach to solving the problem is proposed. Moreover, the authors proposed a mechanism for obtaining an optimal solution for a two-dimensional field model (which is the subject matter of the claimed invention) with the possibility of its further use for a three-dimensional model, which also significantly saves computational resources. The inventive method that implements the choice of a development system using two-dimensional logic can be a tool for preliminary justified screening of unprofitable development options, when calculating development parameters of objects in conditions of lack of information to build a three-dimensional geological and hydrodynamic model, if necessary, to quickly evaluate development options when assessing accuracy not a priority. Regarding the prototype, the inventive method is characterized by high performance, a large number of developed variants of the development system without loss of data processing quality.

So, in the framework of the proposed method, based on the use of a two-dimensional model of the field, determine: the type of development system, the deformation of the development system, method of completion of wells, the time of testing of injection wells for oil. And within the framework of the three-dimensional model, the location of each well is determined by the area occupied by the field, the location of each well through the reservoir, the operation mode of each well, which is much more complicated and requires more powerful computing resources.

As input and output parameters used in the implementation of the proposed method using the following parameters, combined into groups that characterize.

• Development system

• Type of completion

• formation parameters

• Economy

• Calculation Parameters

• Calculation results

As the parameters characterizing the development system, can be used:

Тип системы разработки - реализовано пять систем (пяти-, девяти, семи-, шести-, восьмиточечная)

Type of development system - five systems are implemented (five, nine, seven, six, eight point)

Плотность сетки скважин (Га/скв)

Well Grid Density (ha / well)

Отношение а0/b0 (отношение расстояния между скважинами в ряду к расстоянию между рядами скважин в начальный момент времени)

The ratio of a0 / b0 (the ratio of the distance between the wells in a row to the distance between the rows of wells at the initial moment of time)

Смещение рядов по горизонтали

Horizontal row offset

Основное направление стресса (град) - это направление используется для деформации системы

The main direction of stress (hail) - this direction is used to deform the system

Азимут трещин (град)

Azimuth of cracks (hail)

Коэффициент деформации сетки

Mesh strain factor

Минимальное расстояние между забоями (м) - допустимое расстояние между стволами скважин, без учета трещин.

The minimum distance between the faces (m) is the allowable distance between the boreholes, excluding cracks.

Направление системы (град) - поворот системы на рисунке интерфейса, все углы отображаются относительно этого направления

System direction (degrees) - system rotation in the interface image, all angles are displayed relative to this direction

Пределы для оси X (м) - задается минимальный и максимальный предел

Limits for the X axis (m) - the minimum and maximum limits are set

Пределы для оси Y (м) - задается минимальный и максимальный предел

Limits for Y-axis (m) - the minimum and maximum limits are set

Development systems are in the form of rows, where a0 is the distance between wells in the same row, b0 is the distance between rows. The following relation is fulfilled: the well grid density = a0 * b0, during deformation, the systems a0 and b0 change, but their product must be constant. In the six-point and eight-point systems, the indicated ratio for the grid density of wells is performed only for production wells, for injection wells the density will be 2 times less (six-point) and 3 times less (eight-point).

As parameters characterizing the type of well completion, the following can be used:

For producing wells:

Забойное давление (атм)

Bottom pressure (atm)

Диапазон давлений для подбора (атм) - задается минимальное и максимальное допустимые значения

Pressure range for selection (atm) - sets the minimum and maximum allowable values

Скин фактор

Skin factor

Радиус скважины (м)

Well radius (m)

Тип скважины (наклонно-направленная скважина (ННС), горизонтальная скважина (ГС) с обсаженным стволом, ГС с открытым стволом)

Well type (directional well (HHC), horizontal well (HS) with cased hole, HS with open hole)

Полудлина трещины (м) - если трещины нет, тогда должно быть значение 0

Half-length crack (m) - if there is no crack, then the value should be 0

Проницаемость трещины (Д) - в случае бесконечной проницаемости должно стоять значение - 1

The permeability of the crack (D) - in the case of infinite permeability should be the value - 1

Ширина трещины (м)

Crack width (m)

Длина горизонтального ствола (м)

Horizontal Barrel Length (m)

Направление горизонтального ствола (град)

Direction horizontal trunk (hail)

Длина дополнительного горизонтального ствола (м)

Additional horizontal stem length (m)

Направление дополнительного горизонтального ствола (град)

Direction of an additional horizontal trunk (hail)

Количество гидроразрывов пласта (ГРП) в горизонтальной скважине. Если ГС с открытым стволом без ГРП, должно быть значение 0. Для ГС с обсаженным стволом значение должно быть больше 0, в случае если полудлина трещины равна 0, к-во МГРП воспринимается как к-во перфораций

The number of hydraulic fracturing (HF) in a horizontal well. If the open hole HS does not have a hydraulic fracturing, the value should be 0. For a hole with a cased hole, the value should be greater than 0, if the half-length of the crack is 0, the number of fracturing waves is perceived as perforations

Коэффициент эксплуатации скважин (меняется от (0; 1]). Данный коэффициент применяется ко всем типам скважин (доб. и наг.). Время разработки увеличивается на 1/k раз, а дебит уменьшается в k раз, чтобы сохранить накопленные показатели.

Well utilization rate (changes from (0; 1]). This factor applies to all types of wells (ext. And nag.). The development time is increased by 1 / k times, and the flow rate decreases by k times in order to preserve the accumulated indicators.

Учет поправки Вогеля или Руэда для ГРП (да или нет)

Accounting Vogel or Rueda amendment for hydraulic fracturing (yes or no)

Давление насыщения (атм)

Saturation pressure (atm)

Зависимость забойного давления от времени.

The dependence of bottomhole pressure on time.

For injection wells:

Забойное давление (атм)

Bottom pressure (atm)

Скин фактор

Skin factor

Радиус скважины (м)

Well radius (m)

Тип скважины (ННС, ГС с обсаженным стволом, ГС с открытым стволом)

Type of well (NNS, GS with cased hole, HS with open hole)

Полудлина трещины до и после отработки скважины (м)

Half-length cracks before and after well completion (m)

Проницаемость трещины до отработки (Д) - в случае бесконечной проницаемости устанавливают значение - 1

The permeability of cracks to mining (D) - in the case of infinite permeability set the value - 1

Проницаемость трещины после отработки (Д) - в случае бесконечной проницаемости устанавливают значение - 1

The permeability of the crack after mining (D) - in the case of infinite permeability set value - 1

Ширина трещины (м)

Crack width (m)

Длина горизонтального ствола (м)

Horizontal Barrel Length (m)

Направление горизонтального ствола (град)

Direction horizontal trunk (hail)

Количество ГРП в горизонтальной скважине. Если ГС с открытым стволом без ГРП, параметру присваивается нулевое значение.

The number of hydraulic fracturing in a horizontal well. If the open hole without a hydraulic fracture is, the parameter is assigned a zero value.

As the parameters characterizing the reservoir, can be used:

Oil properties:

Вязкость (сП - пл. ус.)

Viscosity (cp - pl. Us.)

Объемный коэффициент (м3/м3)

Volume coefficient (m3 / m3)

Плотность (г/см3 - пов. усл.)

Density (g / cm3 - pov. Usl.)

Максимальная относительная проницаемость

Maximum relative permeability

Степень по Corey

Corey degree

Газосодержание (м3/м3)

Gas content (m3 / m3)

Water properties:

Вязкость (сП - пл. ус.)

Viscosity (cp - pl. Us.)

Объемный коэффициент (м3/м3)

Volume coefficient (m3 / m3)

Плотность (г/см3 - пов. усл.)

Density (g / cm3 - pov. Usl.)

Максимальная относительная проницаемость

Maximum relative permeability

Степень по Corey

Corey degree

Начальная водонасыщенность

Initial water saturation

Связанная водонасыщенность

Bound water saturation

Максимальная водонасыщенность

Maximum water saturation

Reservoir properties:

Эффективная толщина (м)

Effective thickness (m)

Проницаемость (мД)

Permeability (MD)

Отношение горизонтальной проницаемости к вертикальной

The ratio of horizontal to vertical permeability

Пористость

Porosity

Общая сжимаемость (1/атм)

Overall Compressibility (1 / atm)

Начальное пластовое давление (атм)

Initial reservoir pressure (atm)

Относительные фазовые

Relative phase

Коэффициент Дейкстра-Парсонса.

Dijkstra-Parsons coefficient.

Коэффициент охвата

Coverage rate

As the parameters characterizing the economy, can be used including:

Площадь месторождения (Га)

The deposit area (ha)

Получение результатов на конкретную дату (месс.). Параметры оптимизации, по которым определяются лучшие результаты, рассчитываются на эту дату.

Getting results on a specific date (mass.). Optimization parameters, which determine the best results, are calculated on this date.

Темп бурения (скв/год). Если задать значение - 1, все скважины полагаются введенными в эксплуатацию в один день

Drilling rate (SLE / year). If the value is set to - 1, all wells are assumed to be commissioned on the same day.

Цена нефти (руб/т)

Oil price (rub / ton)

Ставка дисконтирования (в год)

Discount rate (per year)

Срок амортизации (года)

Duration of depreciation (year)

Затраты на добычу жидкости (руб/т)

The cost of production of fluid (rubles / ton)

Затраты на добычу нефти (руб/т)

Costs of oil production (RUB / t)

Затраты на добычу воды (руб/т)

The cost of production of water (rubles / ton)

Затраты на закачку (руб/т)

Download costs (RUB / t)

Содержание скважины (тыс. руб/год/скв)

Well maintenance (thousand rubles / year / SLE)

Содержание куста (тыс. руб/год/куст)

The maintenance of a bush (thousand rubles / year / bush)

Стоимость бурения вертикальной скважины (млн. руб.)

The cost of drilling a vertical well (million rubles)

Стоимость бурения горизонтальной скважины

The cost of drilling a horizontal well

Стоимость обустройства скважины (млн. руб/скв)

Well construction cost (mln. Rubles / SLE)

Стоимость обустройства куста (млн. руб/куст)

Cost of arrangement of the bush (mln. Rub / bush)

Стоимость обустройства месторождения (млн. руб/Га)

The cost of field construction (mln. Rubles / ha)

Стоимость проведения ГРП (млн. руб/стадия)

Cost of fracturing (mln. Rubles / stage)

Стоимость проппанта (млн. руб/т)

The cost of proppant (million rubles / ton)

Плотность проппанта (т/м3)

The density of the proppant (t / m3)

Пористость проппанта

Proppant porosity

As the parameters characterizing the calculation, can be used:

Расстояние между точечными источниками (м)

Distance between point sources (m)

Parameters for calculating the unsteady (non-stationary) filtering mode. The unsteady filtering mode — pressure and / or flow rate change over time. The mode in which the redistribution of pressure has not yet reached the boundaries of the reservoir and / or until the influence of neighboring wells.

Время отработки нагнетательных скважин (сут)

Injection wells test time (days)

Общее время расчета

Total calculation time

Относительная ошибка для прерывания нестационарного расчета.

Relative error for interruption of non-stationary calculation.

Parameters for calculating the steady (stationary) mode of calculation

The established filtration mode is the distribution of pressure and flow rate constantly in time.

Время стационарного расчета

Stationary calculation time

Шаг по времени

Time step

Количество рядов скважин - определяет точность решения

The number of rows of wells - determines the accuracy of the solution

Количество линий тока

Number of current lines

The current line is a line, the direction of the tangent to which at each point coincides with the direction of the velocity of the particle of liquid at this point. A set of streamlines gives an idea of the fluid flow at a given point in time.

Критическая обводненность - максимальная обводненность до значения которой будет строиться характеристика вытеснения

Critical water cut - maximum water cut to the value of which the displacement characteristic will be built

Максимальное количество итераций, после достижения которого процесс автоадаптации останавливают

The maximum number of iterations, after which the process of auto-adaptation is stopped

Погрешность, после достижения данного значения процесс автоадаптации прекращается

Error, after reaching this value, the auto-adaptation process is terminated

As the parameters characterizing the results of calculations, can be used:

Результат по критерию - NPV

The result for the criterion - NPV

Результат по критерию - КИН

The result for the criterion - CIN

Результат по критерию - EMV

The result for the criterion - EMV

Количество лучших результатов

The number of the best results

After entering all input and variable (enumerated) parameters, perform the following steps:

1) form a pattern of the development system element based on the algorithm for calculating the coordinates of the wells for the given development system parameters;

That is, for each development system (five-, six-point, etc.) (as well as for each deformation variant of the development system), a development element is distinguished. In all development systems with a geometrically ordered arrangement of wells, an elementary part (element) characteristic of this system as a whole can be distinguished (Fig. 2). By folding the elements, they get a template for the entire field development system.

2) determine the flow rate of all wells included in the generated pattern of the development system element, for which wells with different types of completion are included in the pattern, are presented as point sources, then, given the values of downhole pressure, using the solution of the steady-state filtration equation, determine the flow rates of all point sources ; [Masket M. The flow of homogeneous liquids in a porous medium. - Moscow-Izhevsk: Institute of Computer Science, 2004, 628 pages.]

The equation of steady filtration is a special case of the piezoconductivity equation for an incompressible viscous fluid.

In the framework of the claimed invention, the wells are point sources / drains operating with constant pressure. 3) on the basis of the obtained flow rates of all point sources, the geometrical parameters of the current tubes are determined (the part of the transported fluid flow limited by the current lines), while the beginning of the tubes is the point sources corresponding to the injection wells, and the end sources point sources corresponding to the production wells; From each source simulating the injection well, the current lines are traced. The current lines are traced by the stationary pressure field for the single-phase case.

From the block diagram shown in FIG. 1 follows the main stages of the proposed method. The formation of a set of initial data characterizing the reservoir is disclosed in the blocks “Indication of the necessary input parameters”, “Calculation of the dependence of the coverage coefficient on the length of the current tubes”, “Algorithm for calculating the modified phase permeabilities”. The algorithms of the last two indicated blocks allow to take into account the lithological heterogeneity of the reservoir structure and the variability of permeability along the section. The formation of a template for an element of a development system is disclosed in the “Calculation of well coordinates in a regular development system” section. Steps 2-7 of paragraph 1 of the claims are disclosed using the “Calculation of filtration at baseline effective oil-saturated thickness for one of the development system options”, “Calculation of two-phase filtration”, “Calculation of unsteady single-phase filtration”, “Cross-linking two-phase solution with unsteady solution” blocks. The calculation of auto-fracturing cracks is performed using algorithms of the same block. Steps 8-11 of clause 1 of the claims describe the algorithms of the blocks “Depth of wells on a thickness map”, “Calculation of profitable wells”, “Calculation of the total dynamics of production and injection by profitable wells”, “Calculation of economic indicators on the total dynamics of production and injection”. A local optimal development system option corresponding to one set of input parameters of the reservoir structure can be selected by successively iterating the development system parameters and well completion types to determine the value of the complex target parameter for each option. The algorithms for finding the local optimal variant are combined in the flowchart with a blue rectangle (local optimization block). The choice of the optimal variant taking into account the variability of the parameters of the reservoir structure (uncertainty) is performed according to the external optimization path (yellow rectangle in the diagram) (global optimization block).

- determination of the heterogeneity of the structure of the reservoir through the IOPS (modified relative phase permeability) and the dependence of the coverage coefficient on the length of the current pipes

When calculating the modified phase permeability curves (OFP), the following limitations and assumptions are made:

The system is linear and horizontal, isothermal, incompressible and obeys Darcy's law. At the initial moment of time, there is only oil and bound water. Neglect gravitational and capillary forces. Throughout the system, the same phase permeability. The thickness distribution of permeability is lognormal. Porosity is constant throughout the model and is equal to the average value over the real reservoir. The algorithm for calculating the IOPS is presented in [N. El-Khatib "Waterflooding Performance of Communicating Stratified Reservoirs With Log-Normal Permeability Distribution" - SPE Reservoir Eval. & Eng. 2 (6), December 1999.]. An example of calculating an IOPS for the Dykstra-Parsons parameter 0.7 (the parameter characterizing the variance of the lognormal distribution) is presented in FIG. 5. (Oil viscosity 1 cP; water viscosity 0.5 cP; relative phase permeability with associated water saturation 1 d.s.; relative phase permeability of water with a residual oil saturation 0.3 c.e.)

The dependences of the coverage factor k on the length of the current tubes L can be defined as the stitching of two functions:

An example of such a relationship is shown in FIG. 6

This option can be used in cases where the geological field data allows you to delineate each lens of a heterogeneous plateau separately and establish its size. Knowing the dimensions of each lens, as well as its volume in shares of the total volume of the collector, it is possible to construct, using the methods of mathematical statistics, the distribution function of the lenses by horizontal and vertical dimensions. These distribution functions contain a sufficient amount of information and can be used to determine the desired dependency. It should be noted that such a calculation is rarely possible at the stage of evaluation of new deposits. Information from several exploration wells is not enough to delineate each lens. Therefore, the necessary information can be obtained from data from a well-studied field of analogue. Based on the data on the lithological structure of the reservoir of the analogue, the size distribution functions of the lenses are determined. This requires either a detailed geological model, or ready-made histograms on the size of the lenses after contouring. After calculating the distribution functions, the coverage ratio depending on the length of the current tubes can be determined as follows:

Where ƒ (r) is the probability density by the longitudinal dimensions of the lenses; P (L, r) is the probability that the lens of size r will be simultaneously opened by the well of the producing series and the well of the injection row, H (r) is the dependence of the thickness of the lens on its longitudinal size, L is the distance between the extractive and injection rows. The function P (L, r) is written as:

An example of determining the dependence of the coverage factor on the length of the current tubes is shown in FIG. 7

- definition of auto-fracturing (hydraulic fracturing)

и среднее давление pave для элемента разработки в случае однофазной фильтрации. Запишем дебит нагнетательной скважины как:The point source method can be used to find a stationary solution for any regular development system of any configuration (see the section below), that is, the flow rates are found.

and the average pave pressure for the design element in the case of single-phase filtration. We write the flow rate of the injection well as:

- функция безразмерного давления нагнетательной скважины. Важно отметить, что эта функция зависит только от геометрии системы разработки и не зависит от давления и свойств флюида. Аналогично находится

добывающей скважины. В общем случае p_D можно представить в следующем виде:Where

- function of the dimensionless pressure of the injection well. It is important to note that this function depends only on the geometry of the development system and does not depend on pressure and fluid properties. Similarly, is

production well. In general, p _D can be represented as follows:

- эффективный радиус скважины с учетом трещины ГРП, ƒ - константа зависящая от режима течения, в данном случае ƒ=0, S - скин-фактор на скважине, для горизонтальной скважины S'=S+S_gor, где where a is the area of the drainage zone,

is the effective radius of the well taking into account hydraulic fracture, ƒ is a constant depending on the flow regime, in this case ƒ = 0, S is the skin factor at the well, for a horizontal well S '= S + S _gor , where

- скин-фактор за счет схождения потока к горизонтальному стволу.

- skin factor due to the convergence of the flow to the horizontal trunk.

- константа Эйлера, C_A - форм фактор.S _A - skin factor associated with the shape of the drainage zone

- Euler constant, C _A - form factor.

,Let the initial half-length of the fracture at the injection well be set

,

в случае

- радиус скважины. Найдем форм-фактор нагнетательной скважины:Then

when

- well radius. Find the injection form factor:

пусть

Также известно среднее пластовое давление p_ave. Пересчитаем новый дебит добывающей скважины с учетом подвижности и давления, функция безразмерного давления известна, тогда:Consider a situation where there are two phases: water and oil with their mobility

let be

Also known is the mean reservoir pressure p _ave . Let us recalculate the new flow rate of the production well, taking into account mobility and pressure, the function of dimensionless pressure is known, then:

найдем его из равенства дебитов:In case of crack growth, Auto-fracturing at the injection well changes

find it from the equality of debits:

Then we will find the new value of the half-length of the crack.

приводит к изменению

Задача согласования решается итерационно: полученное значению

подставляется вместо

и находятся новые

и p_ave. Далее определяется

и снова рассчитывается

Указанные действия выполняются до тех пор, пока разница

не будет меньше расстояния между источниками а. В этом случае значение

больше не меняется и согласуется с

Общая схема представлена на фиг. 8.This value is not consistent with the function of the dimensionless pressure of the production well, since the change

leads to change

The reconciliation problem is solved iteratively: the obtained value

substituted instead

and are new

and p _ave . Next is determined

and again calculated

The specified actions are performed as long as the difference

there will not be less than the distance between the sources a . In this case, the value

no longer changes and is consistent with

The general scheme is shown in FIG. eight.

- calculation of the average well flow rate in a regular development system.

Wells with an arbitrary completion method can be modeled with a set of simple elements: vertical wells, hydraulic fracture section, horizontal section. The general scheme for calculating the flow rate of an average well is shown in FIG. 9.

- simulation of vertical wells at steady state.

For one well, the stationary pressure perturbation is determined by the formula:

where P _k is the pressure on the supply circuit R _k , P is the pressure at a distance r <R _k from the well, q is the well flow rate (negative for production and positive for injection), μ is the fluid viscosity, k is the formation permeability, h is the thickness reservoir.

Due to the linearity of the piezoconductivity equation for a well system, the total pressure perturbation is defined as the sum of the pressure perturbations created by individual wells. In the case of a regular well location, you can use the well-known formula [Kristia N. “Underground hydraulics” —M: State Scientific and Technical Publishing House of Oil and Mining-Fuel Literature, Vol. 2, 1962, 490] to calculate the field pressure around an infinite gallery of wells of the same type. Taking into account the above (intermediate calculations are omitted), the system of equations for determining well flow rates at known bottomhole pressures is written in the form:

where q _j is the flow rate of wells located along the x axis at a distance a from each other, r _cj is the reduced radius of the well j taking into account the skin factor, x _{i, j} , y _{i, j} are the coordinates of the point sources simulating the well.

The calculation of flow rates of wells with hydraulic fracturing, taking into account the resistance of the proppant with a linear kinematic law of flow inside the fracture, is reduced to solving a system of linear algebraic equations:

- проницаемость пласта, N_grp - количество источников имитирующих трещину ГРП, N _{a νto} - количество источников имитирующих трещину авто-ГРП,

- длина участка между i-1 и i источниками трещины, K_grp - проницаемость трещины ГРП (проппанта), a _i - здесь ширина трещины ГРП.where μ is the viscosity of the fluid, h is the thickness of the reservoir,

- reservoir permeability, N _grp - the number of sources simulating a fracture fracture, N _{a νto} - the number of sources simulating a fracture auto-fracturing,

- the length of the section between the i-1 and i sources of the fracture, K _grp - the permeability of the hydraulic fracture (proppant), a _i - here the width of the hydraulic fracture.

- Calculation circuit current tubes

The calculation of the geometry of the current tubes is made on the already determined values of the flow rates of all sources and sinks in the development system. To trace current lines, it is necessary to solve the system of equations:

This system of equations is solved by the Runge-Kutta method for some initial values of x ₀ and y ₀ . The current lines are produced from injection wells belonging to the central element. Each current tube is characterized by the initial flow rate of the fluid, the length and the variable pore volume along the S coordinate. An example of the calculation of current tubes for a five-point well pattern is shown in FIG. ten.

- a scheme for determining technological indicators

The determination of technological parameters is carried out using a stationary system of current tubes based on the solution of the two-phase filtration equations. In a dimensionless form, the two-phase filtration equation is written as:

- накопленный безразмерный отбор жидкости. Решение уравнения для насыщенности при известных зависимостях относительных фазовых проницаемостей позволяет определить распределение водонасыщенности по длине для каждой трубки тока. Это позволяет определить динамику закачки и объемных отборов жидкости, нефти в пластовых условиях. Далее при известных плотностях и объемных коэффициентах нефти и воды для каждой трубки тока рассчитываются массовые показатели в поверхностных условиях. Для определения динамики технологических показателей элемента системы разработки массовые отборы нефти и воды и объемы закачки суммируются по всем трубкам тока. Для определения динамики технологических показателей средней скважины массовые отборы нефти и воды элемента разработки делятся на количество добывающих скважин в элементе, объем закачки делится на количество нагнетательных скважин в элементе разработкиwhere σ is the normalized water saturation, ƒ is the Buckley-Leverett function, y is the dimensionless pore volume of the current tube element,

- accumulated dimensionless fluid withdrawal. The solution of the equation for saturation with known dependences of relative phase permeabilities allows determining the water saturation distribution along the length for each current tube. This allows you to determine the dynamics of injection and volumetric withdrawals of fluid, oil in reservoir conditions. Then, with known densities and volume coefficients of oil and water, mass indices are calculated for each current tube in surface conditions. To determine the dynamics of the technological indicators of the element of the development system, mass selections of oil and water and injection volumes are summed over all current tubes. To determine the dynamics of the technological parameters of an average well, the mass extraction of oil and water of a development element is divided by the number of producing wells in the element; the injection volume is divided by the number of injection wells in the development element.

- consideration of the geometric coefficient of coverage

Geometric well coverage ratio is the proportion of the pore volume involved in the process of displacing oil by water.

Кроме того, происходит аналогичное снижение дебита жидкости. Наиболее проста и понятна трактовка коэффициента охвата как снижение толщины трубки тока H_ochν,n=HK_ochν,n.For a particular current tube, the coverage factor K _{ochν, n} is known. In this case, according to the previous definition of the coverage ratio, the pore volume of the current tube involved in the displacement process will be

In addition, a similar decrease in flow rate occurs. The simplest and most understandable interpretation of the coverage ratio as a reduction in the thickness of the current tube H _{ochν, n} = HK _{ochν, n} .

To take into account the coverage ratio in production figures, the previously calculated indicators should be multiplied by the coverage ratio for each current tube, depending on its length.

- the scheme for determining the flow rate in unsteady mode

The equation for pressure distribution is:

- коэффициент пъезопроводности. Пористость - m, проницаемость - KWhere

- coefficient of conductivity. Porosity - m, permeability - K

Fluid viscosity μ. Compressibility of a porous medium with liquid C.

If the well rate is set for a well, the solution for pressure distribution is written in the form of the Duhamel integral. The problem of determining the flow rate of a fluid at a constant bottomhole pressure is reduced to finding the function

q (t) from the integral equation:

where P ₀ is the initial reservoir pressure. Bottom pressure P _s .

If we assume that the flow rate of a fluid is a piecewise constant function, and using the principle of superposition, we can calculate the dynamics of unsteady flow rates for a system of wells. Moreover, at each time step it is necessary to solve a system of algebraic equations for the current well flow rates.

If there are fractures with a finite conductivity, this system of equations should be supplemented with a system of equations for calculating bottomhole pressures at sources simulating cracks.

- stitching two-phase solution with the decision on unsteady flow to the well

от КИН, где

- дебит жидкости в начальный момент времени. Решение нестационарной задачи позволяет получить зависимость нестационарного дебита жидкости от времени в условиях однофазной задачи. Для восстановления дебита нефти от времени на нестационарном режиме выполняется следующая процедура:The solution of the stationary (stationary in geometry of current tubes, but non-stationary in saturation) two-phase problem allows one to obtain the displacement characteristic (dependence of the water content on the CIN) and the dependence

from kin where

- fluid flow rate at the initial moment of time. The solution of a non-stationary problem allows to obtain the dependence of a non-stationary flow rate of a liquid on time under the conditions of a single-phase problem. To restore the oil production rate from time to time in the non-stationary mode, the following procedure is performed:

из решения нестационарной задачи. Характеристика вытеснения актуальна только с этого момента времени. Рассчитывается накопленная добыча жидкости за i период

1. At the time of launching the injection well, the flow rate is known.

from solving a non-stationary problem. The extrusion characteristic is relevant only from this point in time. Calculated cumulative fluid production for i period

2. According to the well-known characteristic выт _{b of} displacement and with the known extraction of liquid, oil production is calculated. For this it is necessary to solve the differential equation:

where E is the CIN (at the time of the start of the injection well E = 0), b ₀ is the initial water cut.

рассчитывается КИН, затем определяется поправка на дебит жидкости на i+1 период:3. Determining the cumulative oil production for the i period

the CIN is calculated, then the correction for the flow rate of the liquid is determined for the i + 1 period:

The procedure is performed from the first step with a new fluid flow rate. The calculation ends when the required maximum calculation time is reached.

- consideration of the drained thickness and thickness of exhausted

Оставшуюся, не охваченную заводнением часть коллектора Н-H_ochν можно учесть, если рассмотреть эту часть как работающую в режиме истощения. При этом дебит скважины в начальный момент будет определяться полной толщиной Н. Для учета данного эффекта выполняется два расчета: для толщины H_ochν рассчитывается дебит

по модели двухфазного вытеснение; для толщины H-H_ochν рассчитывается дебит

на нестационарном режиме без закачки (режим истощения). Тогда суммарный дебит скважины будет равным:When taking the coverage factor into account, it was assumed that only a fraction of the thickness was covered by the two-phase filtration process

The remaining, not covered by the waterflood part of the _{HH ochν collector} can be _taken into account, if we consider this part as operating in depletion mode. At the same time, the flow rate of the well at the initial moment will be determined by the total thickness H. To take into account this effect, two calculations are performed: for the thickness H _{ochν the} flow rate is calculated

on the model of two-phase displacement; for the thickness HH _ochν calculated rate

on non-stationary mode without injection (depletion mode). Then the total well flow rate will be equal to:

Q (t, H) = Q _2ph (t, H _ochν ) + Q _ist (t, HH _ochν )

- calculation of production dynamics taking into account the rate of well input

After calculating the dynamics of oil and fluid production of an average well for the basic effective oil-saturated thickness q _b , the flow rate can be calculated for any thickness value of the effective thickness map. For this it is convenient to present the map of oil-saturated thickness in the form of a histogram. For this, the thickness map should be represented as a set of N _c cells with sides Δх × Δу. For each cell j, its own average effective cell oil thickness h _{j is given} . Further, the entire range of thickness changes is divided into N "pockets":

min (h) <min (h) + Δh <min (h) + 2Δh <... <max (h)

The number of cells in each pocket is determined:

The proportion of the total area within each “pocket” by thickness is determined:

where S is the total area of the field. Wherein

The wells are entered from large thicknesses to smaller ones, i.e. determination of the number of wells for drilling in each "pocket" occurs from right to left. The number of wells for drilling in each “pocket” is determined based on the area per well for the calculated development system s _w .

итого «кармана» (меньший, чем площадь, приходящаяся на одну скважину) добавляется к

«карману».Square brackets, in this case, denote integer division. The remaining area of

The total “pocket” (smaller than the area per well) is added to

"Pocket".

The average net oil thickness is calculated for each “pocket”:

Calculate the average profile of production wells for each "pocket":

where q _b (i) is the well production profile calculated for the base thickness, h _b is the base thickness.

After calculating the well production dynamics, profitable wells are determined for all thicknesses. The algorithm for determining cost-effective wells is presented below.

- accounting of project economics

а также объем закачки воды

в поверхностных условиях для каждой скважины. Для выбранной системы разработки известно соотношение добывающих и нагнетательных скважин

The dynamics of mass oil and water sampling under surface conditions are known.

as well as the volume of water injection

in surface conditions for each well. For the chosen development system, the ratio of production and injection wells is known.

and the total planned number of wells in the bush N _kust

calculation of capital costs to determine profitable wells:

The volume of one-off investments in the first settlement month, consisting of:

• costs for filling and engineering preparation of St _kust bushes (filling of the cluster pad, discharge lines, platform for the oil and gas equipment base, etc.);

• well construction costs, including completion method

• equipment costs that are not included in the St _onss construction estimates (tubing, cables, pumps, etc.);

For one well, the calculation of unit costs to account for the cost of the hive is as follows:

The cost of well construction depends on the depth of the object of development and the method of completion of the well, that is, on the length and width of the hydraulic fracture, the length of the horizontal wellbore, the number of cracks and horizontal wells (for complex wells). In general, the cost of well construction can be described by the following relationship:

затраты на проведение ГРП на нагнетательных и добывающих скважинах

costs of hydraulic fracturing at injection and production wells

- базовая стоимость операции проведения ГРП, a _grp и b_grp коэффициенты, определяющие стоимость используемого проппанта в зависимости от высоты трещин

и полных длин трещин

- the base cost of the fracturing operation, a _grp and b _grp coefficients that determine the cost of the used proppant depending on the height of the fractures

and full length cracks

затраты на бурение горизонтальных стволов нагнетательных и добывающих скважин

costs for drilling horizontal wells in injection and production wells

- базовая стоимость бурения горизонтального ствола, b_hor - затраты на бурение одного метра горизонтального ствола,

- полная длина горизонтальных стволов на нагнетательных и добывающих скважинах.Where

- the base cost of drilling a horizontal _wellb , b _hor - the cost of drilling one meter of a horizontal well,

- the full length of horizontal wells in injection and production wells.

The cost of equipment that is not included in the construction budget (ONSS), in general, depends on the choice of the pump, the depth of its suspension, as well as the additional equipment of the well. In general, assuming that the choice of pump is determined by the potential well flow rate, the cost of the onc can be described by the following relationship:

- затраты на установку дополнительного оборудования в нагнетательных скважинах,

- затраты на НКТ, насос и дополнительное оборудование в добывающих скважинах.Where

- the cost of installing additional equipment in injection wells,

- the cost of tubing, pump and additional equipment in production wells.

The total capital costs per production well are calculated:

Next, the depreciation is determined

where T _{a m} is the depreciation term in years.

calculation of operating costs to determine profitable wells

Operating costs consist of:

• oil production costs;

• liquid extraction costs;

• water injection costs;

• well maintenance costs;

• the cost of maintaining the bushes.

The cost of oil production is proportional to the volume of oil production and are defined as

where P _o - specific variable costs of production of 1 ton of oil.

The cost of fluid production is proportional to the volume of fluid production and are defined as:

- удельные переменные затраты на добычу 1 тонны жидкости.Where

- specific variable costs of extraction of 1 ton of fluid.

The cost of water injection is proportional to the volume of water injection and are defined as:

where P _inj - specific variable costs for the injection of 1 m ^{3 of} water.

The cost of maintaining the well are defined as:

where C _scν - specific fixed costs for the maintenance of 1 well per month.

The cost of maintaining bushes is proportional to the number of bushes and are defined as

where C _kust - specific fixed costs for the maintenance of 1 bush per month.

The total operating costs of a single production well are as

- calculation of profitable wells

According to the dynamics of the technological indicators of each well of the development system and the economic parameters for each month, the following calculations are made: The income from the sale of oil is determined:

where Cena is the price of 1 ton of oil.

Determined operating costs OP ^j

CAP ^j capital costs are determined.

The mineral extraction tax is determined:

where γ _NDPI is the MET rate.

The property tax is determined:

where γ _sar is the property tax rate

Profit tax is determined

where γ _prib is the income tax rate.

Net cash flow determined

Determined by the accumulated discounted flow

where Disk is the annual discount rate.

Calculations are carried out before reaching the limit water cut, or the maximum value of the accumulated discounted flow. Let it correspond to the moment of time j _rent . Then the condition of profitability of wells is written as:

This condition divides wells into cost-effective and non-cost-effective ones.

- calculation of project economics

After the formation of a set of profitable wells is determined by the total dynamics of production for them.

The total NPV is determined by the same formulas as the previous section, the difference is in the determination of capital costs. In addition to the already calculated costs, it is necessary to take into account the costs associated with the construction of the S _field and the costs associated with the maximum capacity S _qmax (which depend on the maximum total fluid flow rate). With this in mind, capital costs are written as:

- selection of the optimal system for a single geological implementation

Optimization of the development system is associated with the selection of many parameters that can be divided into two groups

1. Parameters characterizing the actual development system (the ratio of production and injection wells, the relative position of the wells, grid density, etc.)

2. Parameters characterizing the method of completion of wells included in the development element.

The optimization process can be carried out according to various economic and technological criteria (achievement of maximum NPV, achievement of maximum profitability index PI, achievement of maximum oil recovery factor (KIN), etc.). In addition, complex criteria can be implemented - complex target parameters (for example, reaching the maximum NPV at the maximum oil recovery ratio).

As is known, when choosing the optimal variant in the presence of more than one criterion, it is possible to select only a set of equivalent solutions, each of which claims to be optimal (Pareto set). To select a single solution, additional research and the formation of an additional criterion are necessary. The problem of optimization in the presence of several mutually independent criteria can be solved by forming a complex criterion. This can be done using a fuzzy logic device. The integrated optimization target parameter can be written as

F = φ [ψ ₁ (τ ₁ ), ₂ (τ ₂ ), ..., _n (τ _n )]

where τ _i is an optimization criterion, ψ _i is an optimality function by criterion τ _i , φ is an optimization function by a set of criteria (usually a weighted average, or geometric average).

- the choice of the optimal system, taking into account the uncertainty of the geological structure of the reservoir

Let the probability p _j be given for each of the parameters j, which determine one specific geological description of the reservoir used in the calculations (this could be porosity, average net weight, initial oil saturation, etc.). Considering the parameters independent, the probability of finding one specific joint implementation of the parameters is calculated as:

where the index i denotes one of the possible implementations.

Let NPV values be calculated for one development option m and for all possible geological implementations of N. In this case, EMV (Expected Monetary Value - Expected Monetary Value) can be calculated using:

The optimal variant of the development system, taking into account the uncertainty of the geological structure of the reservoir, corresponds to the variant with the maximum value of EMV, that is:

EMV ₁ = max (EMV ^m ), m = 1 ... M

EMV optimization is possible if there is quantitative information about the uncertainties of the reservoir structure, i.e. the required distribution functions of such parameters as porosity, permeability, average oil saturated thickness, initial oil saturation, etc. At the same time, optimization by EMV reduces the risk of making extremely non-optimal decisions on the development system if the parameters of the reservoir structure are not confirmed.

A specific example

The inventive method was used to select the optimal development system in the area of one of the largest fields in Western Siberia. The selected area is characterized by low values of reservoir properties. The previously used development system in these conditions was not effective, which was confirmed by the development of neighboring areas with similar filtration-capacitive properties.

To select the most effective version of the development system, a series of calculations was carried out. Three development system patterns, shown in FIG. 12. For each template, they changed (sifted): displacements of a number of injection wells relative to a number of producing wells (frontal or chess arrangement, Fig. 13; method of completion of wells and the length of horizontal wells (Fig. 14); area per well (Fig. 15a), deformation parameter of the development system a / b (a - distance between wells in a row, b - inter-row distance, fig. 15b). The total number of calculation options exceeded 4 thousand. The ranges and values of variable parameters of the development system are presented in table 1.

NNS - directional well;

Hydraulic fracturing - hydraulic fracturing;

PPD - reservoir pressure support;

MGRP - multistage fracturing;

HS - horizontal well;

VNS + hydraulic fracturing option - production and injection wells are directional. All well with fractured fracturing.

Variant GS + NNS (PPD) + hydraulic fracturing - production wells are horizontal with several fracturing fractures, injection wells are directional with hydraulic fracturing.

Variant GS + MGRP - all wells (both injection and production) are horizontal. All wells used technology MGRP.

Table 1 also shows the lengths of horizontal wells (500, 750, 1000 m) for the variants in which horizontal wells were used.

The optimization was carried out according to the complex target parameter of the profitability index (PI) and oil recovery ratio (CIN), namely:

Where

The maximum and minimum values of PI and CIN were determined over the entire calculated sample of N≈4000 variants.

In all cases, option “1” with an offset of 0.5 turns out to be more effective than any other options considered. In the future, all the arguments are given for options "1" with an offset of 0.5.

For convenience of displaying the results of calculations on two-dimensional graphs, the dimensionless parameter S / L ² was introduced, where S is the area per well, L is the length of the horizontal wellbore for the mountains. wells or full length fractures for directional wells with hydraulic fracturing. The total length of each fracture in all cases except for auto-fracturing was 200 m. The calculation of auto-fracturing was performed according to the algorithm above.

The dependence of the complex parameter on the deformation parameter of the a / b system for the five best options is shown in FIG. 16a.

To assess the risk of fracture fracture deviation from the direction of horizontal shafts, a sensitivity analysis was performed for the five best options. All the cracks in the sensitivity calculations synchronously rotated relative to the wellbore at a random angle in the range from 0 to 30 degrees. For each case, 30 realizations were calculated. For all implementations, the standard deviation was determined by PI and CIN. FIG. 16b, with deviations shown by thin or dashed lines. The smaller the standard deviation, the more stable the variant for fracture fracture rotation. It should be noted that the CIN at a zero angle of rotation is maximum and any rotation of cracks leads to its reduction. Thus in FIG. 16c shows the deviation only downward.

From FIG. 16a, b, s, it can be seen that the variant S / L ² = 0.36 with a / b = 4 corresponds to the maximum value of the parameter ƒ (≈0.97). At the same time, the standard deviation and the mean PI value (Fig. 16b) for this option at point a / b = 4 coincides with the S / L ² = 0.49 option, but the ORF value, even taking into account the risk of crack rotation, is higher (Fig. 16c) . It should be noted that due to the definition of the parameter ƒ the largest value of the complex parameter does not correspond (is in a different range of values of a / b) to neither the maximum of PI, nor the maximum of CIN. The best option is characterized by 36 hectares of reservoir area per well, with a HS length of 1000 m, inter-row distance of 300 m, 1,200 m between wells in a row (200 m between ends of wells), number of hydraulic fracturing stages equal to 7, production and injection wells are horizontal. This option was recommended for drilling. The proposed and implemented well location patterns are shown in FIG. 17 ( a , b). There are minor differences associated with technological limitations during drilling, which are not taken into account in the presented approach. In general, the main recommendations have been retained.

The claimed technical solution can be used for preliminary selection of obviously unprofitable development options, when calculating the parameters of development of facilities in conditions of lack of information to build a three-dimensional geological and hydrodynamic model, as well as the need for rapid evaluation of development options when the accuracy of the assessment is not a priority.

Claims (19)

1. The method of selecting a field development system, which is the determination of the area location of wells, including - formation of a set of initial geological, topographic, geophysical data characterizing the reservoir; - determining the set of output variable parameters characterizing the development system, with the following steps for each of the types of the development system and each variable parameter of the development system being performed to ensure the well flow rate over time: 1) form a pattern of the development system element based on the algorithm for calculating the coordinates of the wells for the given development system parameters; 2) determine the flow rate of all wells included in the generated pattern of the development system element, for which wells with different types of completion included in the pattern are presented as point sources, then the flow rates of all point sources are specified as input data using downhole pressure solving the steady state filtration equation; 3) on the basis of the obtained flow rates of all point sources, the geometrical parameters of the current tubes are determined, while the beginning of the tubes is the point sources corresponding to the injection wells, and the point sources corresponding to the production wells are considered the end; 4) perform a calculation of two-phase unsteady filtration of incompressible liquids along each current tube, resulting in a distribution of water and oil saturation along each current tube, as well as the dynamics of oil production, water production / injection for all point sources; 5) carry out the summation of solutions for all sources corresponding to each well, resulting in a stationary two-phase solution for well flow rates, which is the displacement characteristic (water content dependence on oil recovery factor (KIN)) and

from oil recovery rate where

- fluid flow rate at the initial moment of time; 6) perform the calculation of single-phase flow rates of all point sources that simulate wells in an element of a development system using the piezoconductivity equation using the method of quasistationary approximations, after which a non-stationary single-phase solution for flow rates, characterizing the dependence of flow rates on time, is obtained by summing single-phase flow rates for all point sources, appropriate wells; 7) according to the displacement characteristic obtained in step 5) and non-stationary single-phase well rates in step 6), a single-phase non-stationary solution and a stationary two-phase solution are combined, resulting in oil and water production dynamics, water injection for all wells in a fixed system element baseline formation thickness, which is a solution for an average well; 8) determine the flow rates of wells based on their location on the thickness map, after which they are ranked from large thicknesses to smaller ones according to the geometrical parameters of the development system element template and based on the comparison, wells with a positive net present value (NPV) are distinguished; 9) for the selected wells perform the calculation of total profiles of oil production, fluid and injection; 10) determine the dynamics of gas production based on the obtained oil production profiles on the basis of gas content; 11) total NPV is determined by total profiles of oil production; 12) steps 1) -11) are repeated for each type of development system and for each other value of the parameter being sorted in one development system, then, according to the maximum value of the complex target optimization parameter, the most optimal field development system is selected. 2. The method according to p. 1, characterized in that as the source data using the thickness chart or one average value of the thickness of the reservoir, the average permeability of the reservoir, the average porosity of the reservoir, fluid parameters (PVT), namely the bottomhole pressure, saturation pressure for oil, fluid viscosity, volume density coefficients, ranges of reservoir properties (FES) of the reservoir, ranges of parameters of relative phase permeability (OFP), ranges of changes in the parameters of the development system. 3. The method according to claim 1, characterized in that the output variable parameters of the development system use the type of development systems, the type of well completion and design parameters, namely the density of the development system (S), α is the ratio of the number of producing wells to injection, the ratio the distance between the wells in the row (a) to the distance between the rows of wells (b), the stretch ratio of the pattern of the development system along a given direction. 4. The method according to claim 1, characterized in that the value of the total NPV, or CIN, or the profitability index PI, or the value of the maximum NPV at the maximum CIN, is used as a complex optimization target parameter.

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