RU2484242C2 - Monitoring and control system and method of well flow rate - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: system and method for increasing a well flow rate are described in the application. The system includes processor (150) that processes commands contained in a software, which include command for monitoring during the specified period of time of an actual fluid flow rate from each productive zone (52B, 52b) of the well in compliance with the first tuning of devices for control of the flow rate and applying the analysis of the chain using a method of node potentials to a variety of input data chosen from the data of well sensors, data of surface sensors, one or more current positions of devices, for the purpose of setting one or more new settings, at which increase in the well flow rate will be provided.

EFFECT: increasing productive capacity of well.

18 cl, 6 dwg

Description

FIELD OF THE INVENTION

The present invention relates generally to the control (monitoring) of well operation and hydrocarbon production from such wells.

State of the art

In order to produce hydrocarbons (oil and gas), wells are drilled in the rock strata. Some of these wells, drilled vertically or almost vertically, pass through several formations or productive zones. Deviated and horizontal wells that pass through productive zones mainly horizontally, i.e. mainly along the length of the reservoir. In some cases, branches from various wells are drilled from the main well. Often, several wells located at a certain distance from each other are drilled in these layers or at oil fields. In order to optimize hydrocarbon production, a description or model of the formation is first created, usually representing the initial approximate representation of the real formation and its behavior. Based on this initial model, a development plan is usually developed and wells are commissioned. As the reservoir depletes, its state changes and the information collected at this stage of production is used to update the reservoir model in order to optimize the total volume of production from the reservoir. Such an optimization cycle is usually developed in order to optimize the total production volume at the field and improve understanding of the actual structure of the formation. This process usually continues throughout the life of the field until the end of the life of the formation. It often takes a very long time to incorporate current formation information into the reservoir model, apply it in an updated development plan, and raise funds for drilling and completion of new wells. This is a process of successive approximations in which it can often take from several months to several years for each successive approximation of a model.

Another optimization cycle is associated with improving or maximizing the technological performance of individual wells. During this cycle, the technological parameters of the well are monitored and compared with the calculated technological parameters of the well. Measures are being taken to restore production to an estimated level. Such a cycle traditionally ends by invading a well or by performing surface control actions.

Relatively complex wells are usually fastened with casing pipes that line the wellbore. Certain constant sensors are installed in the well to monitor certain parameters of the well and the rock strata surrounding the well. To control the flow rate of fluid from one or more productive zones, remote-controlled valves and fittings are installed in the well. Chemical reagents or additives are often injected into wells from a surface source to suppress the formation of deposits, corrosion, hydrates, asphaltenes, etc. in the well. To raise the fluid extracted from the rock strata to the surface, a pump-compressor (mechanized) production facility is sometimes placed in the well, such as an electric submersible pump (ESP) or a natural gas injection system.

The operator usually analyzes the data from various downhole and surface sensors and devices, and interprets such data in order to calculate or evaluate the condition of the well. The operator sends control systems that control the downhole and ground-based devices commands to make the necessary changes to the production of fluids from the well. Such actions may include changing the operation of the EPN, closing or opening valves and fittings, changing the injection of chemicals, etc. Such a cycle to a large extent involves the interpretation of data by the operator and intervention by the operator, which can be fraught with errors or take a relatively excessive time, resulting in certain circumstances may result in incorrect actions and (or) delay in the implementation of one or more actions. Such interpretation and actions may also not lead to a proper increase or maximization of well production over a selected period of time, which may be the period of operation of the well.

Thus, there is a need for an improved system and method for monitoring (monitoring) the state of the well and for taking actions that can maximize or maximize well productivity by controlling fluid production from such a well.

Summary of the invention

A method for producing fluid from a completed well is proposed, in which: (i) as a function of time, the expected flow rate of the fluid entering the well from at least one production zone is calculated in accordance with the first setting of at least one downhole flow control device, which allows fluid from the productive zone to enter the well, (ii) over a certain period of time, the actual flow rate of the fluid entering the well from at least one production zone is monitored Twi with the first setting of at least one device for controlling flow rate, (iii) using a computer model and a set of input data selected from downhole sensor data, data from ground sensors and at least one downhole device parameter, set taking into account the downward trend in the actual flow rate of at least one second setting of at least one flow control device, in which the flow rate of fluid from at least one production zone increases to a level exceeding the expected aemy fluid flow rate from at least one production zone, (iv) and the operation is carried out well in accordance with at least one second setting to increase fluid production from at least one production zone. According to the method, based on at least one second setting, a second fluid flow rate over a long time from at least one production zone can be calculated. Then, based on at least one second setup, the net present value (NPV) of the well can be calculated.

The input data may be selected from data relating to well pressure, flow rate, surface flow rate, operating parameters of an electric submersible pump, flow rate of injected chemicals, temperature, resistivity of a rock or fluid, fluid density, fluid composition, fluid capacity measurement results; vibrations in the well, results of acoustic measurements in the well, differential pressure in the well device, water content, water-oil factor, gas-oil factor and gas-water factor. Other data and measurements may also be used, including but not limited to microseismic measurements, variable pressure test results, well measurement results, measurement results regarding the presence of one or more chemicals in the well, which may include deposits, hydrate, corrosion, and asphaltene . According to another feature of the method, the probability of one or more events, including water breakthrough, cross flow, wear of the casing of the well or wear of the downhole device, can be calculated, and then a second setting or settings can be set based on this calculation. Other settings may be made in order to take into account changes in the flow rate of injected chemicals, the operation of EPN, the closure of the selected productive zone, etc. According to another feature, an operator located near the well and / or at a remote location may receive messages about the second setting. After a new set-up of devices is carried out, actual production can be continuously monitored. Then this process is repeated. The method also provides that based on at least one second setting, the expected fluid flow rate from the well or production zone is updated.

According to another feature, a system is proposed for increasing the production rate of a well having multiple productive zones, a separate device for controlling production rates for each production zone, and a device for tubing production, which includes a computer system having a processor, a computer-readable medium for storing computer programs and data, available a computer for executing instructions contained in a computer program, and a display for displaying information transmitted by the processor, while the computer program ma comprises (i) a set of control commands for a certain period of time the actual flow rate of the fluid from each production zone in accordance with a first setting of each flow control device and the flow through the device for production tubing; 2 one device for regulating the flow rate in order to increase the flow rate of the well and (iii) a set of commands to continue to control the increased flow rate corresponding to the new setting.

Examples of a system and method for monitoring the physical condition of production well equipment and controlling the flow rate of the well, outlined in sufficient general terms, will be disclosed in the following detailed description to better understand both them and additional features of the claims.

Brief Description of the Drawings

In order to provide a detailed understanding of the system and methods for monitoring and regulating the production rate of production wells described and claimed in the invention, refer to the accompanying drawings, in which similar elements are usually indicated by the same positions and which show:

figure 1 is a high-level block diagram of a closed-loop control system (monitoring) and well management according to one of the features of the invention,

on figa and 2B is a schematic diagram of a well operation system for producing fluid from a variety of productive zones according to one of the possible embodiments,

figure 3 is an example of a block diagram of a control system that can be used in the well operation system, including the system shown in figa and 2B, to perform various measurements relating to the well, determine the desired actions that can be taken to increase production wells, the automatic implementation of one or more of these actions, predicting the impact of such actions and monitoring the behavior of the well after the implementation of such actions,

figure 4 is an example of a curve of pressure over time in a production well, such as, for example, shown in figa and 2B, which according to one of the features of the invention is applicable to control the flow rate of the well,

figure 5 is an example of a diagram illustrating the expected behavior of the well, such as shown in figa, and the actual behavior of such a well, as well as examples of the moments when described in the invention system can perform one or more necessary actions, and well behavior after the implementation of such actions, and

6 is a functional block diagram illustrating the software of the well behavior analyzer, which can be used to analyze data and create an action plan to increase production in relation to the cycle 1A shown in figure 1.

Detailed description

Figure 1 shows a high-level block diagram of a production system 1, which includes a cycle or system 1A increase and optimization of the flow rate of a particular well, combined with a system or cycle 1B to optimize the operation of the reservoir or field. Before starting development of the field with the aim of oil and gas production, create a model or cycle 1B. The implementation and updating of cycle 1B is a relatively lengthy process and aims to optimize the operation of the field. Cycle 1B may include a field development plan 7 indicating the location, depth, and type of wells to be drilled. The plan is usually based on the geological and physical characteristics of layer 6, which can use data from various sources, including seismic data (two-dimensional or three-dimensional maps), data from other deposits in the region; analysis of rocks for potentially productive formations, etc. With the help of economic analysis, a program of 8 investments in drilling and completion of wells in the field is being developed. At stage 9, the plan is implemented and updated based on information about the behavior of the wells.

According to one of the features, cycle 1A is a closed cycle that can be designed to increase or maximize production from a particular well in the field. Throughout cycle 1B, the well control system continuously monitors or measures various parameters of the 2 wells, which include parameters in the well and on the surface; carries out continuous diagnostics or analysis of 3 different data, including previous well data and current measurement results from a variety of downhole and ground sensors, using programs, models and algorithms developed for 1B system; and creates an action plan 4, when the results of the analysis indicate that the production rate of the well is outside the selected or desired range. Action plan 4 may contain actions proposed by the operator for changing one or more parameters of the well, such as changing the flow rate from one or more zones, changing the flow rate of injected chemicals or changing the operation of the EPS, etc.

According to one of the features, after the operator performs one or more actions, the well continues to be monitored by means of a system or cycle 1A, the effect of the performed actions on the well flow rate and other parameters is calculated, and the analysis is continued and messages are transmitted to the operator as necessary. According to another feature, system 1B can be designed to automatically intervene (step 5) and to carry out or ensure the implementation of one or more actions. It can be initiated if the operator does not take any action or performs an inadequate action, or if the condition of the well serves as the basis for certain actions, which may include any of the actions proposed to the operator, and other actions that may be acceptable in emergency situations, such as water breakthrough, cross flow, etc. System 1A can be designed to take any action, including stopping production from any zone of the well or shutting down an electric submersible pump, pumping chemicals, etc. The action of the system or cycle 1 in relation to one example of a well is described in more detail with reference to figures 1-5.

On figa and 2B schematically shows a system 10 of a well operation according to one embodiment of the invention. On figa shows a production well 50, equipped with shown by way of example equipment, devices and sensors that can be used to implement the ideas and methods described in the invention. On figb shown for example, ground equipment, devices, sensors, controllers, computer programs, models and algorithms that can be used to control and maintain, increase, optimize or maximize the flow rate of the well 50. According to one of the features of the system 10 is designed periodic or continuous use of the measurement results from various sensors and other data to determine well behavior, including flow rate from each production zone, the status of various devices system 10, predict the behavior and condition of the well 50 and its related equipment, including sand production, water inlet, water breakthrough, cross flow, water front position and condition of various devices, etc. According to another feature, the system 10 can be designed to determine the necessary actions that can be taken to increase or maximize the flow rate of the well 50 according to the selected criteria. According to another feature, the system 10 can be designed to transmit to the operator and (or) at other addresses the desired messages and warning signals regarding the condition of the well and the necessary adjustments or actions regarding various operating modes of the well 50 to perform one or more of the following: , increase, optimization, or maximize well production; mitigating or eliminating the negative impact of the potential or actual occurrence of a harmful condition, such as the accumulation of certain chemicals, such as deposits, corrosion, hydrates and asphaltenes, potential or actual breakthrough of water, cross flow or wear of certain equipment, etc.

According to another aspect, the system 10 may be configured to monitor the actions taken (if any) by the operator in response to messages transmitted by the system; updating any actions taken after adjustments made by the operator; the implementation of the selected adjustments if the operator does not take certain actions; automatic control and monitoring of one or more devices or equipment of the system 10; and transmitting status reports to the operator and to other addresses, including one or more remote locations. According to another feature, the system 10 can be designed to establish two-way communication with one or more remote points and / or controllers through one or more appropriate data lines, including the Internet, wired or wireless lines, and using one or more appropriate protocols, including internet protocols.

On figa shows a well 50 drilled in a thickness of 55 rocks for the production of reservoir fluids 56A and 56b from two (for example) production zones 52a (upper production zone) and 52b (lower production zone), respectively. It is shown that well 50 is secured by casing 57 with perforations 54a near the upper production zone 52a and perforations 54b near the lower production zone 52b. Packer 64, which may be a removable packer located above or above the wellbore than the perforations 54a, isolates the lower production zone 52b from the upper production zone 52a. A filter 59b may be installed near the perforations 54b to prevent or suppress the ingress of solid particles, such as sand, into the well table from the lower production zone 54b. Similarly, near the perforation holes 59a in the region of the upper production zone, a filter 59a can be used to prevent or suppress the ingress of solid particles into the well 50 from the upper production zone 52a.

The formation fluid 56b from the lower production zone 52b through the perforations 54a enters the annular space 51a of the well 50 and into the tubing string 53 through the debit control valve 67. The debit control valve 67 may be a remotely controlled spool valve or any other suitable valve or fitting that is capable of adjusting the flow of fluid from the annular space 51a to the production tubing 53. To control the flow of fluid from the lower production zone 52b to the surface 112 in the tubing string 53 can be used with an adjustable fitting 40. The formation fluid 56a from the upper production zone 52a through the perforations 54a enters the annular transtvo 51b (the annulus portion above the packer 64a). Formation fluid 56a through inlets 42 enters a production tubing string or line 45. An adjustable valve or nozzle 44 connected to line 45 controls fluid flow through line 45 and can be used to control fluid flow to surface 112. Each valve , the fitting or other such device in the well can be controlled electrically, hydraulically, mechanically and (or) pneumatically from the surface. Fluid from the upper production zone 52a and the lower production zone 52b flows through line 46.

In cases where the reservoir pressure is not sufficient to push fluid 56a and / or fluid 56b to the surface, mechanized (pump) equipment, such as an electric submersible pump (ESP), can be used to lift fluids from the well to surface 112 gas lift system. As an equipment for pump and compressor production in system 10, an EPN 30 mounted on a manifold 31 is shown, into which formation fluids 56a and 56b are supplied and which, through a pipe system 47, pumps fluids to surface 112. Cable 134 supplies power to the EPN 30 from a ground source 132 power (figb), which controls the block 130 control EPN. The cable 134 may also have bi-directional data lines 134a and 134b, which may be one or more electrical conductors or fiber optic communication lines providing a bi-directional signal and data exchange line between the EPI 30, the EPI sensors S _E and the EPI control unit 130. According to one of the features, the operation of the EPN 30 is controlled by the EPN control unit 130. The EPN control unit 130 may be a computer system, which may contain a processor, such as a microprocessor, memory, and programs for analyzing and controlling the operation of the EPN 30. According to one of the features, the controller 130 receives signals from the sensors S _E (FIG. 2A) regarding the actual pump discharge frequency, EPN performance, pressure and fluid temperature in EPN 30, and can receive measurement results or data regarding certain chemicals, such as corrosion, deposits, asphaltenes, etc., and reagir apply them or other calculations in order to control the operation of the EPN 30. According to one of the features, the EPN control unit 130 can be designed to change the speed of the EPN by transmitting control signals 134a in response to data received on line 134b or commands received from another the controller. The EPN control unit 130 may also cut off power to the EPN via a power line 134. According to another feature, the EPN control unit 130 may transmit EPI data and information (frequency, temperature, pressure, chemical sensor data, etc.) to the central controller 150, which in turn can transmit control signals or commands to the EPN control unit 130 for providing selected operating modes of EPN 30.

To control various devices in the well 50 and obtain measurement results and other data from various downhole sensors, a variety of hydraulic, electrical and data lines have been laid inside the well 50 (generally indicated at 20 (FIG. 2A)). For example, through a pipe system 21 from the surface, a particular chemical can be supplied or pumped into the fluid 56b through the mandrel 36. Likewise, through a pipe system 22, a particular reagent can be supplied or pumped into the fluid 56a through a production tubing via mandrel 37. Lines 23 and 24 can be used to control any other device, such as valve 67. Line 25 can serve to supply power to some downhole devices from an appropriate ground source. Two-way data lines between the sensors and / or their respective electronic circuits (generally indicated by 25a and located at any one or more of the corresponding positions in the well) can be installed in any desired way, including, without limitation, wires, optical fibers, acoustic telemetry a communication channel using a hydraulic line; electromagnetic telemetry, etc.

According to one aspect, various other sensors are located at respective positions in the well 50 to transmit measurement results or information regarding a number of well parameters of interest. According to one of the features in the production tubing string can be located one or more holders of measuring instruments or sensors, such as holder 15 to accommodate any number of relevant sensors. The holder 15 can accommodate one or more temperature sensors, pressure sensors, sensors for measuring flow rate, sensors for measuring resistance, sensors transmitting information about density, viscosity, water content or water cut, etc. and chemical sensors that transmit information about deposits, corrosion, asphaltenes, hydrates, etc. Density sensors can be instruments for measuring the density of fluid coming from each productive zone and the density of the combined fluid from two or more productive zones. A resistance sensor or other appropriate sensor may take measurements related to the water content or water cut of the fluid mixture from each production zone. Other sensors may be used to calculate the oil-water factor and the gas-oil factor for each productive zone and the combined fluid. Temperature, pressure, and flow sensors measure temperature, pressure, and fluid flow rate through line 53. To support measurements of pressure, temperature, fluid flow rate, and water content in the formation fluid coming from upper production zone 52a, additional measurement instrument holders can be used. To perform measurements regarding the chemical characteristics of the well fluid, such as the content of paraffins, hydrates, sulfides, sediments, asphaltene, emulsion, etc., additional downhole sensors at other desired positions may be used. In addition, sensors S _i -S _m can be permanently installed in the borehole 50 for acoustic or seismic or microseismic measurements, formation pressure and temperature measurements, resistivity measurements and measurements of casing 51 and rock thickness 55. Such sensors can be installed on the casing 57 or between the casing 57 and a thickness of 55 rocks. In addition, filter 59a and / or filter 59b may be coated with indicator substances that are released in the presence of water, which can be detected on the surface or in the well and allows for the detection or prediction of water breakthrough. Sensors can also be installed on the surface, such as a sensor for measuring the water content of the incoming fluid, the total volume of the incoming fluid, wellhead fluid pressure, temperature, etc. Other devices can be used to calculate sand removal for each zone.

In general, enough sensors can be appropriately placed in the well 50 to measure each desired parameter of interest. Such sensors may include, without limitation, sensors for measuring pressure in each productive zone, pressure throughout a selected portion of a wellbore, pressure inside pipes for supplying formation fluid, pressure in the annular space; sensors for measuring temperature at selected points along the wellbore; sensors for measuring fluid flow rate in each of the productive zones, total flow rate, EPN productivity; sensors for measuring temperature and pressure in EPN; chemical sensors for signaling the accumulation of chemicals, such as hydrates, corrosion, deposits and asphaltene; acoustic or seismic sensors for measuring signals generated on the surface or in neighboring wells, and signals associated with fluid migration from injection wells or with fracturing operations; optical sensors for measuring chemical composition and other parameters; sensors for measuring various characteristics of the rock thickness surrounding the well, such as resistivity, porosity, permeability, fluid density, etc. Sensors can be installed on a pipe system in a well or on any device, or can be permanently installed in a well, for example, on a casing of a well, on a wall of a wellbore, or between a casing and a wall. The sensors may be any suitable type of sensors, including electrical sensors, mechanical sensors, piezoelectric sensors, fiber optic sensors, optical sensors, etc. The downhole sensor signals may be partially or fully processed in the wellbore (such as by a microprocessor and associated electronic circuits capable of exchanging signals or data with downhole sensors and devices), and then transmitted to the ground controller 150 via a signal / data transmission line, such as a line 101. The signals of downhole sensors can also be transmitted directly to the controller 150.

As shown in FIG. 2B, system 10 further comprises a surface unit 120 for pumping chemicals to supply additives 113a to the well 50 and additives 113b to the surface unit 170 for cleaning the fluid. The desired additives 113a from source 116a (such as a reservoir) can be injected into the well 50 via injection lines 21 and 22 using an appropriate pump 118, such as a direct displacement reciprocating pump. Additives 113a flow along lines 21 and 22 and flow into collectors 30 and 37. The same or separate discharge lines can be used to supply additives to different productive zones. Separate injection lines, such as lines 21 and 22, allow independent injection of various additives at different depths of the well. In this case, various sources of additives and pumps are used to store and pump the desired additives. Additives can also be injected into a surface pipeline, such as line 176, or a surface treatment and processing plant, such as block 170.

A corresponding flowmeter 120, which may be a low-flow rate high-precision flowmeter (such as a gear type flowmeter or a rotary flowmeter), measures the fluid flow rate through lines 21 and 22 and transmits signals reflecting the corresponding flow rates. A pump 118 is controlled by a corresponding device 122, such as an engine or a compressed air driven device. The stroke of the pump and (or) the speed of the pump can be controlled by the controller 80 through the master circuit 92 and the control line 122a. The controller 80 may control the pump 118 by using programs stored in the memory 91 associated with the controller 80 and / or the commands transmitted to the controller 80 by the central controller or processor 150 or the remote controller 185. The central controller 150 communicates with the controller 80 via a corresponding two-way line 85, which may be a wired, fiber optic or wireless connection, and using one or more of the appropriate protocols. The controller 80 may include a processor 92, a resident memory 91 for storing programs, tables, data and models. The processor 92 uses the signals of the flow rate measuring device received on line 121 and the programs stored in the memory 91 to determine the flow rate of each of the additives and displays such flow rates on the display 81. The sensor 94 is capable of providing information about one or more parameters of the pump, such like pump speed, piston stroke length, etc. For example, the pump speed or piston stroke length can be increased when the measured amount of injected additive is less than the desired amount, and reduced when the injected amount is greater than the desired amount. The controller 80 also contains circuits and programs, generally indicated at 92, to facilitate interaction with the local display 81 and to perform other desired functions. The level sensor 94a provides information on the remaining contents of the source 116. Alternatively, the central controller 150 may transmit to the controller 80 instructions regarding injection of additives, or may act as a controller 80. Although FIG. 2A-2B illustrates one production well, it is understood that An oil field may have many production wells, and a variety of wells may also be located, such as neighboring wells, injection wells, and test wells. is, well, etc. The instruments and devices shown in the drawings may be used on any number of such wells and may be configured to work together or independently.

Figure 3 shows a block diagram of an example well operation system 200 that can be used to control, increase, optimize, or maximize well production and optimize formation operation. The system 200 includes a central control unit or controller 150, which contains one or more processors, such as a processor 152, corresponding storage devices 154, and corresponding circuits 156, designed to implement various functions and methods described in the invention. System 200 includes a database 230 of data stored on a suitable computer-readable medium accessible by processors 152. Database 230 may contain: (i) data and information about completion, such as types and locations of sensors in the well, sensor parameters , types of devices and their parameters, such as type and size of fittings, position of fittings, type and size of valves, position of valves, wall thickness of casing pipes, etc .; (ii) formation characteristics, such as rock type for different layers of the formation, porosity, permeability, mobility, resistivity and depth of each layer and production zone; (iii) sand filter parameters; (iv) information on indicator substances; (v) EPI parameters, such as power, frequency range, and operating pressure and temperature ranges; (vi) data on the behavior (operational indicators) of the well for the past period, including flow rate over time for each production zone, pressure and temperature indicators over time for each production zone; (vii) current and previous settings for fittings and valves; (viii) intervention and maintenance information; (ix) sand and water data over time for each productive zone; (x) source seismic data (two- or three-dimensional maps) and updated seismic data (four-dimensional seismic maps); (xi) water front monitoring data; (xii) and any other data that may be useful to control and increase well flow rate 50.

During the period of operation of the well, one or more tests are usually carried out collectively indicated by 224 in order to calculate the health of various elements of the well and various parameters of the productive zones and layers of the formation surrounding the well. Such tests may include, but are not limited to, casing checks using electrical or acoustic probes; closed well tests, which may include high or variable pressure tests, heating and flow tests; seismic studies in which a surface source and seismic sensors in the well can be used to determine the conditions of the water front and the boundary of the strata; microseismic measurements, such as tests after hydraulic fracturing or water injection operations; fluid front control tests; secondary mining tests, etc. All data 224 of such tests can be stored in memory and transmitted to the processor 152 to control the flow rate of the well 50, to analyze, increase, optimize or maximize the flow rate of the well 50 and optimize reservoir operation.

In addition, processor 152 of system 200 may periodically or continuously access downhole sensor measurement data 222, ground-based measurement data 226 and any other desired information or measurement data 228. The downhole sensor measurement data 222 includes, but is not limited to, water content or water cut, resistivity, density, viscosity, sand content, flow rate, pressure, temperature, chemical properties or fluid compositions, gravity, slope, electrical and electromagnetic measurements, oil and gas, oil and water fluid factors and fittings and valve positions. The data of 226 ground measurements include, without limitation, data on flow rates, pressures, positions of fittings and valves, EPI parameters, calculations of water content, rate and location of chemical injection, data on detection of indicator substances, etc.

System 200 also includes programs, models, and algorithms 232 embedded in one or more computer-readable media available to processor 152 to execute instructions contained in programs. The processor 152 may use one or more programs, models, and algorithms to perform various functions and methods described in the invention. According to one of the features of the program / model / algorithms 232 can be implemented in the form of a well behavior analyzer (APS), which is used by the processor 152 to analyze some or all of the measurement data 222, 226, test data 224, information from the database 230 and any other desired information accessed by the processor to calculate or predict one or more parameters of the well’s operation.

According to one of the features, the processor can be configured to determine fluid flow rate from each zone, such as zones 52A and 52B shown in FIG. 2A, and total flow rate, comparing such flow rates with expected flow rates and performing actions when the actual flow rates fall below the expected level, as shown in block 260. As noted earlier, in the initial stages of the formation optimization cycle 1B shown in FIG. 1, a plan for the expected well production is created. 5 is a graph 500 illustrating a hypothetical expected decline in production rate curve 510 of a well 50. Production decline curve 510 shows the dependence of the expected oil production rate plotted on the vertical axis and production time (in years) plotted on the horizontal axis. Curve 550 shows the actual productivity of the well 50. At the start of the countdown, the well is put into operation and production begins at level 552, while production exceeds the expected level until it falls below the expected level at time 556.

APS analyzes the data using the results of measurements of one or more sensors, information from the database and test data, as well as the current settings of various devices for regulating flow rate, and determines the actions that will result in an increase in the flow rate of the well to the expected level or levels exceeding expected . To determine the actions that can be taken to increase the production rate of the well, the APS uses models, programs and algorithms. For this purpose, the APS can also use chain analysis using the nodal potential method and can calculate elevated production levels after the specified actions have been taken. The processor transmits to the operator and the remote controller 185 messages 262 containing the proposed actions. The processor can also periodically or mainly continuously display certain information on the display 262 for use by the operator and / or the remote controller 185, and this information can without limitation contain production data from each zone, data on the current settings of valves and fittings, frequency and performance data , data on the accumulation of chemicals in the well, water cut data for each zone, etc. Proposed actions may include changing the frequency of EPN, changing the flow rate of injected chemicals, changing the setting of fittings and valves, etc. APS can also calculate the estimated impact of one or more proposed changes on production and the impact of cumulative changes. In some situations, it may be desirable to reduce production from one zone and increase production from another zone. According to one of the features, the processor waits until the operator makes the proposed changes. If the operator does not perform these actions, the processor can send reminders and send messages to remote locations, including email messages. As soon as the operator carries out the proposed actions, production begins to rise until the moment 558 occurs, and then begins to fall before the moment 560. According to one of the features of the APS, it can be calculated not to expect the production to fall below the expected level corresponding to the moment 556, but to carry out extrapolation based on the production decline curve and transmit to the operator a message indicating one or more actions specified by the processor so that the operator can respond in advance and support up to Bulling at a higher level. Subsequently, the productivity of the well may fall below the expected level, and in the considered example, additional actions that are carried out at the moment 562 do not lead to an increase in oil production to a level higher than expected, therefore, it may be desirable to carry out production by secondary methods. The processor 152 may display the diagrams shown in FIG. 5 on an operator display. The results of the analysis can be transmitted to the remote controller 185, which can use such information to update the model of geological and physical characteristics (cycle 1B, figure 1). The example illustrated in FIG. 5 corresponds to a scenario according to which actual production exceeds expected production based on the original model. In other situations, actual production may begin at a lower rate and may not exceed expected production rates. In any case, the method described above can be applied.

According to another feature, it can follow from the results of the APS analysis that to increase or optimize the production rate of a well, such as well 50, it is more preferable to produce from one zone until the water cut exceeds a selected value. In other words, it may be desirable to produce from one zone until the water cut sensor readings exceed the limit for the cost-effective operation of the well and its equipment. Then, the system 200 overlaps the first zone, opens the second zone, and the production of fluid is carried out as described above, while it is considered cost-effective.

According to another aspect, system 200 can predict the characteristics of a fluid production process from a well and adjust the characteristics of the well to optimize or maximize well production. For example, APS can predict a breakthrough of water or the occurrence of a cross flow or wear of any device or casing, etc., determine the necessary actions and transmit to the operator a message, as described above, about the need to change the characteristics of the well or can automatically perform such actions .

For example, APS can determine the source or sources of water breakthrough such as, for example, location in the productive zone, location in the rock strata above and (or) below the productive zone; cracks in the cement binder between the casing and the rock; location of the water front relative to the well, etc. APS can also determine the degree or severity of an expected water breakthrough and the expected time or period of time when a water breakthrough can occur. To determine a water breakthrough, the central controller 150 may calculate a specific indicator (such as water content, water cut, etc.) regarding the formation fluid (for each zone and / or cumulative flow rate) over a certain period of time and calculate or predict the probability water breakthrough using such calculated indicators of water. The controller 150 may use the trend associated with the water indicator over a certain period of time, or use real or near real time calculated water indicators to detect and / or predict the likelihood of water breakthrough. The water index in the formation fluid can be set by the surface analyzer, which determines the water content or water cut of the produced fluid 224. The water index can include, without limitation, the amount, water cut in percent, limit value, value of the change in values, etc. The water rate or water content in the formation fluid can also be calculated based on the readings of downhole sensors (such as resistivity or density sensors); analysis of indicator substances present in the produced fluid in the well or on the surface; density measurement results; or readings of any other relevant sensors. According to another feature, the processor can predict the likelihood of a water breakthrough by using the results of acoustic measurements made by permanent downhole sensors, or the results of microseismic measurements or four-dimensional seismic maps that indicate the water front related to a specific productive zone, or based on rock cracks associated with productive zone. The processor can also predict the location and degree of water breakthrough based on the calculation of casing wear based on casing inspection data or on the basis of cement binder wear. According to one of the features, the central controller uses proactive models or neural networks to determine the desired actions. These models can, for example, serve to assess the expected effectiveness of one or more actions, the costs associated with the implementation of one or more actions, to perform a comparative analysis of two or more such actions, etc.

After the central controller 150 predicts a potential water breakthrough, it determines the actions that need to be taken to mitigate or eliminate the negative consequences of a water breakthrough and at the same time optimize production as much as possible. The central controller 150 may recommend shutting off a particular productive area by closing a valve or fitting; block all zones; close the fitting on the surface; reduce fluid production from a specific zone; increase the production of fluid from the unaffected zone, change the frequency of the ESP or turn off the ESP; change the flow rate of injected chemicals into the zone, etc. Central controller 150 transmits these recommendations to the operator. If a water breakthrough affects only one of all zones, the system may recommend that fluid is extracted from the potentially affected zone until a certain point, and then block such a zone before a water breakthrough occurs. Alternatively, the system may recommend decreasing production from one zone and continuing production from other zones, or in some cases, the system may recommend increasing production from one or more other zones. According to one of the features of the APS in each case, it can determine the combination of actions that are likely to lead to maximizing the production rate of the well until it is stopped for repair.

As described above, the processor transmits messages to the operator indicating the desired action, transmits such information to the remote controller and displays the desired data for use by the operator. The processor continues to monitor the consequences of the actions taken by the operators, similar to the way described above with reference to FIG. After the operator makes the change, the central controller 150 continues to process the water breakthrough data and continues to operate in the manner described above. According to another feature, when the central controller 150 detects an imminent breakthrough of water or an alarming situation, it may initiate one or more desired actions.

According to another feature, hydrocarbon production can be increased by reducing water withdrawal from productive zones based on the selected criterion. APS can determine the rate of production from various zones, at which the water withdrawal from the well will decrease, but hydrocarbon production from the well will continue or increase. According to one of the features, APS determines such production levels at which pressure is also maintained at the desired level or in the selected range. Then the APS sets the settings of the valves and fittings, the frequency or power supply of the EPS and the flow rate of the injected chemicals. The processor transmits messages to the operator and the remote controller and performs other functions similarly to the way described above.

According to another aspect, the system 200 may contribute to a change in production if a cross-flow is detected or predicted. Under normal operating conditions of the well 50, the pressure in the lower production zone 52B is higher than the pressure in the upper production zone 52a. Under such conditions, formation fluid 56a from the upper production zone will flow in the direction of the surface, as indicated by arrows 77A. However, under certain conditions, the reservoir pressure "Pu" in the upper production zone 52a may begin to increase and subsequently exceed the pressure "Pl" in the lower production zone 52B. As this pressure shift occurs, formation fluid from the upper production zone begins to flow towards the lower production zone. At a certain point in time, the values of pressure Pu and pressure Pl intersect. In such a scenario, it may not be possible to support the production of formation fluids 56a and 56b from the well 50, and one or more downhole devices, such as EPN 30 and the wellbore as a whole, may be damaged. According to one of the features, the central controller 150 continuously calculates the pressures Pu and Pl and uses a model or program to predict the occurrence of an intersection, and also determines one or more actions that must be performed in response to the detection of cross flow. APS can contain one or more models and (or) algorithms that can be based on historical data or laboratory data, or other synthesized data, to determine the expected time of occurrence of the intersection. The models can take into account any number of factors, such as the percentage value by which the pressure in the well exceeds the reservoir pressure, and the duration of this condition; rate of change of pressure Pu and Pl; pressure difference Pu and Pl, temperatures in the upper and lower productive zones; Does the pressure in the annulus (upper zone) exceed the pressure in the tubing (lower zone), and is the lower zone open for fluid production? and the moment when the results of downhole flow measurements indicate that the flow is approaching a crossflow state; and any other desired factors. The central controller also calculates the severity and timing of the potential transverse flow and determines the actions to be taken. The central controller can transmit warning or warning signals simultaneously with the recommendation of one or more actions, including without limitation the recommendations: close or partially close a specific fitting, for example, fitting 40; blocking or restraining the flow of formation fluid 56a along line 45; close spool valve 67; change the speed (frequency) of the EPN 30 or turn off the EPN 30; change the amount of additives 113a or 113b injected into the well 50 and the surface processing unit 170; block or isolate a specific area; reduce surface pressure; open the ground fitting; reduce flow through a specific fitting or close a specific fitting; and any other applicable recommendation. According to one of the features, the recommended actions may be optimization of the well flow rate. The central controller 150 continues to monitor the described characteristics of the well in order to continuously evaluate the impact of changes made by the operator, and continues to provide additional input and recommendations similar to that described in the invention.

According to another feature, system 200 may recommend or take action based on the health of the equipment. For example, system 200 may measure corrosion or build up on any device, such as a valve, or establish that the ESP is operating outside of specified parameters, or measure wear of casing or cement bonding, etc. and, in response, set an action plan that can provide the optimum net present value of the well. System 200 then attempts to implement the plan in a manner predominantly described above.

According to another feature, the APS can analyze the data in order to reduce or minimize the removal of sand from each productive zone. According to one of the features of the processor 152 can control the measure of sand carried out from each zone, and using the analysis of the circuit by the method of nodal potentials to predict the removal of sand from each zone. The processor can control the pressure in each productive zone and, based on it and (or) using other data, calculate the removal of sand or the expected removal of sand from each production zone. Then the processor determines the necessary actions, as a result of which the sand removal will decrease and (or) hydrocarbon production will increase. Actions may include reducing production from the affected area, increasing production from another area, halting production from the affected area, or any combination thereof. Then the MTA transmits messages to the operator through a display showing the actions. Actions may also include changing the speed of the EPS and changing the flow rate of injected chemicals to account for changes in production from different zones. System 200 continues to monitor the impact of changes made by the operator, and can also be designed to go into automatic mode in order to automatically initiate any action.

According to another feature, APS can be designed to analyze variable pressure state data and calculate production from each zone, as well as adjust equipment parameters in order to increase, optimize, or maximize well production. 4 is a diagram 400 illustrating an example of a change in pressure over time in which pressure is plotted on the vertical axis and time is plotted on the horizontal axis. The pressure curve shown corresponds to the period after the productive zone has been closed. The pressure before closing is usually predominantly constant. When the productive zone is closed, the pressure begins to grow slowly over a short period of time, such as the period ending at 412, then it grows predominantly at a constant rate, as indicated by section 414, and then gradually changes, as indicated by section 416. APS analyzes the data variable pressure and sets the settings of various downhole devices of the system 10 in order to increase the flow rate of the well, based on the selected criteria, and transfers the new settings to the operator or automatically sets a new construction device and then continues to monitor the effect of the new settings and provide feedback manner described above.

According to another feature, the APS can analyze well test data and set new production parameters and corresponding new settings. According to another feature, APS can calculate the presence and / or rate of accumulation of chemicals, such as deposits, corrosion, hydrates and asphaltenes, and can calculate their effect on production rates and the health of certain devices, such as valves, fittings, EPN and piping systems . The MTA determines the actions and transmits the appropriate messages to the operator and to the remote locations and performs the tracking functions as described above. Actions may include changing the flow rate of injected chemicals, changing the speed of the EPN, changing the flow from one or more zones, removing valve components and fittings to remove corrosion or deposits, etc.

In some situations, various parameters and settings may be interdependent. For example, if production from one zone is reduced by setting the nozzle to a position of lower throughput, the pressure in the well and flow rate of another zone may change, and a different ESP setting and a different flow rate of injected chemicals, etc. may be required. As another example, the cessation of production from one zone can provide the desired increase in hydrocarbon production, but can cause damage to the EPS, since if its speed decreases to a level corresponding to the rate of production, the EPS can go beyond the specified technical requirements. In such a case, it may be desirable for the ESP to operate at a higher capacity and take a small fraction of the fluid from the zone that was originally selected for closure. According to one of the features in any of the scenarios described above, the APS determines the actions or settings based on the observance of the selected criterion or criteria in order to increase, optimize or maximize the productivity of the well. APS can carry out circuit analysis using the method of nodal potentials or use proactive models to configure various devices.

6 shows a functional block diagram 600, while the APS 610 performs circuit analysis by the method of nodal potentials, uses neural networks and (or) other proactive models to set various operating parameters, such as settings of various devices, and to increase the flow rate of the well with a specific configuration. According to one of the features of the APS 610 receives ground-based measurement data or calculation results based on ground-based measurements 612, downhole measurements or calculation results based on downhole measurements 620, test data 614, information from database 616 and any other information 618 that may be related to specific well, and uses chain analysis using the nodal potential method and (or) other proactive models to set new settings. Chain analysis using the nodal potential method may include predicting the effect of new settings on production and iteration of this process until a combination of new settings (final plan) is obtained, at which there will be an increase, optimization or maximizing the flow rate of a particular well. According to one of the features, the effect of the plan on production at the field may or may not be taken into account. According to another feature, the analysis of the circuit by the method of nodal potentials can be partially based on the analysis of the net present value so that with the new settings the expected total net present cash receipts from the well flow rate will increase, as shown in block 650. The APS is trying to carry out the actions described above.

As shown in FIG. 2B, the central controller can be configured to automatically initiate one or more of the recommended actions, for example, by transmitting control signals to the controllers of selected devices, such as an EPN controller, to adjust the operation of EPN 242; control units or actuators (160, FIG. 1A and element 240) that control downhole fittings 244, downhole valves 246, ground fittings 249, chemical injection control unit 250, other devices 254, etc. Such actions can be taken in real or near real time. At step 264, the central controller 150 continues to monitor the results of the actions taken. According to another feature, the central controller 150 or the remote controller 185 may be configured to update one or more models / algorithms / programs 234 for further use for monitoring the well. Thus, the system 200 can in closed-loop mode control the behavior of the well, carry out or ensure the implementation of the desired actions and continue to monitor the results of such actions.

Although the above description describes some embodiments and methods, various improvements will be apparent to those skilled in the art. It is assumed that all such improvements included in the scope of the attached claims are included in the above description.

Claims (18)

1. A method of producing fluid from a well in which:
calculating the tendency of the expected fluid flow rate as a function of time from the at least one production zone of the well when first setting up at least one downhole flow control device;
monitoring the actual fluid flow rate from the at least one production zone in accordance with this first setting of at least one flow control device;
assessing the likelihood of at least one of the events including a breakthrough of the fluid, a transverse flow, wear of the casing of the well and wear of the downhole device;
using a computer model and a plurality of input data selected from downhole sensor data, ground sensor data and parameters of the at least one downhole flow control device, set based on a tendency to decrease the actual flow rate, different from the trend of the expected fluid flow rate, at least one second setting of said at least one flow control device, in which the actual flow of fluid from the well is expected to change to a level edelyaemogo trend, wherein the second setting is set, based on said probability estimation; and
downhole equipment is configured in accordance with said at least one second setting to provide increased production of fluid from the well. 2. The method according to claim 1, in which, based on at least one second setting, a second expected fluid flow rate over time is additionally determined for the well. 3. The method according to claim 2, in which calculate the net present value for the well based on the second expected flow rate of the fluid. 4. The method according to claim 1, in which the aforementioned set of input data is selected from the group including data regarding pressure in the well, flow rate of the well, flow rate on the surface, operating parameters of the electric submersible pump (EPN), flow rate of injected chemicals, temperature, specific resistance, fluid density, fluid composition, measurement results of capacitance, vibration, results of acoustic measurements, differential pressure in the device, water content, water-oil factor and gas-oil factor Torah. 5. The method according to claim 4, in which said group additionally contains at least one of the following data: microseismic measurement data, variable pressure test results, well log measurements and measurement data regarding the presence of a chemical in the well, related to one of the substances, including deposits, hydrates, corrosion products, asphaltene and paraffin. 6. The method according to claim 1, in which at least one of the parameters related to the flow of injected chemicals, the operation of the EPS and the closure of the selected production zone, if the well has many productive zones, is additionally changed. 7. The method according to any one of claims 1 and 2, in which additionally transmit a message regarding at least one second setting, at least to the operator or to a point remote from the well. 8. The method according to any one of claims 1 and 2, in which at least one second setting involves changing the position of the at least one device, changing the flow rate of injected chemicals and changing the flow rate of the fluid from the downhole mechanized production device. 9. The method according to any one of claims 1 and 2, in which, based on at least one second setting, the expected fluid flow rate is further updated. 10. The method according to claim 1, in which over a certain period of time additionally control the actual flow rate of the fluid from at least one productive zone in accordance with at least one second setting, and taking into account the tendency to decrease the actual flow rate after well operation, at least in the second setup, set the third setup, which increases the flow rate of the fluid from at least one productive zone. 11. A system for providing an increase in the flow rate of a well having a plurality of productive zones, a separate device for regulating the flow rate for each production zone and a device for mechanized production, which includes:
a computer system including a processor, a computer-readable medium for storing computer programs and data with access to a computer for executing instructions contained in a computer program, and a display for displaying information transmitted by the processor, the computer program comprising:
a set of commands for calculating the trend of the expected flow rate of the fluid, as a function of time, from at least one production zone of the well during the first setup of at least one downhole device for controlling flow rate;
a set of commands for monitoring over a certain period of time the actual flow rate of the fluid from each productive zone in accordance with the first setting of at least one device for controlling flow rate and flow through the device for mechanized production;
a set of commands for assessing the probability of occurrence of at least one of the events, including the breakthrough of the fluid, the transverse flow, wear of the casing of the well and wear of the downhole device;
a set of commands for applying circuit analysis using the nodal potential method to a set of input data, including downhole sensor data, ground sensor data and the current position of at least one device for controlling flow rate, so that, based on the tendency to decrease the actual flow rate, which differs from the expected trend fluid flow rate, set a new setting for at least one device for regulating flow rate in order to ensure the flow rate of the well, determined by the trend, and the second setting is set based on from said probability estimate; and
a set of commands to continue monitoring increased flow rate corresponding to the new setting. 12. The system of claim 11, wherein the computer program further comprises instructions for calculating an expected increased fluid flow rate for the well based on the new setting. 13. The system of claim 12, wherein the computer program further comprises instructions for calculating a net present value for the well based on the calculated increased fluid flow rate. 14. The system according to claim 11, in which the aforementioned set of input data is selected from the group including data regarding pressure in the well, flow rate of the well, flow rate on the surface, operating parameter of the electric submersible pump, flow rate of injected chemicals, temperature, resistivity, density fluid, fluid composition, capacitance measurements of the fluid, vibration, results of acoustic measurements, differential pressure in the downhole device, water content, water-oil factor and gas-oil factor a. 15. The system of claim 14, wherein said group further comprises microseismic measurements, variable pressure tests, well measurements, and measurements regarding the presence of a chemical in the well related to one of the substances including deposits, hydrates, and corrosion products, asphaltene and paraffin. 16. The system of claim 11, in which the computer program further comprises a set of commands that use the selected criterion to specify a new setting. 17. The system according to clause 16, in which the selected criterion is at least one of the criteria, including the removal of sand, less than the selected value, the flow of water from the selected productive zone, less than the selected value, the absence of a transverse flow state, wear of the downhole device within the selected limits and the operation of the ESP within the selected limits. 18. The system according to any one of paragraphs.11-12 and 16-17, in which at least one new setting includes many changes, including changing the position of at least one device, changing the flow rate of injected chemicals and changing the flow rate of the fluid from a downhole mechanized production device.

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