Monitoring and control system and method of well flow rate
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
The technical field to which the invention relates.
The present invention relates generally to the control (monitoring) of wells and production of hydrocarbons from such wells.
The level of technology
The purpose of the production of hydrocarbons (oil and gas) in the strata of the rocks drilled wells. Some of these wells are drilled vertically or almost vertically pass through several layers or productive zones. Also spread slanted and horizontal wells that pass through the productive zone is predominantly horizontal, i.e., predominantly along the length of the reservoir. In some cases, from the main wells are drilled branches in different layers. Often in these layers or in the oil fields are drilling multiple wells located at a certain distance from each other. To optimize hydrocarbon production first create a description or model of the reservoir, typically a source approximate representation of a real reservoir and its behavior. Based on this initial model of typically developing plan of development and type of wells in operation. As the depletion layer its status changes and information collected at this stage of production are used to update the reservoir model with the aim of optimizing the total production from the reservoir. This cycle of optimization of the commonly developed with the aim of optimizing the total production of the field and improve understanding of the actual structure of the reservoir. This process usually continues for the lifetime of the field until the end of the life of the reservoir. Often takes a very long time to include current information about the layer in the layer model, to apply them in the updated plan of development and to raise funds for drilling and completion of new wells. It is a process of successive approximations, in which at each iteration of the model can often take several months to several years.
Another optimization loop is associated with improvement or to maximise the technological performance of individual wells. During such a cycle control and compare the performance of the wells with an estimated technological indicators of the well. Measures to restore production to the estimated level. This cycle is traditionally completed by the invasion of the borehole or the implementation of control actions on the surface.
Relatively complex wells usually fixed casing pipes that line the wellbore. In the well establish certain permanent sensors for monitoring certain parameters of the well and surrounding the borehole formations. To regulate the flow of fluid from one or more of productive zones in the well establish remote is about controlled valves and fittings. In wells from a terrestrial source often inject chemicals or additives with the aim of suppressing the formation in the borehole sediments, corrosion, hydrates, asphaltenes, etc. For lifting to the surface of the fluid produced from formations in the borehole sometimes place the tool tubing (mechanized) production, such as electric submersible pump (APN) or a discharge of natural gas.
The operator usually examines data from various downhole and surface sensors and devices, and interprets these data to calculate or estimate the condition of the well. The operator transfers control systems, which control the downhole and surface devices, the commands to make the necessary changes in the production fluids from the well. Such actions may include changing work APN, closing or opening of valves and fittings, changing the injection of chemical reagents, etc. This cycle essentially involves the interpretation of data by the operator and the intervention of the operator, which can be error-prone or take on excessive time, which in certain circumstances may become incorrect actions and(or) the delay in the implementation of one or more actions. This interpretation and action also does not lead to an appropriate increase or to maximize well production rate during the selected time period, who may be the period of operation of the well.
Thus, there is a need for an improved system and method for monitoring the condition of the well and the implementation of actions that can increase or maximize well performance by regulating the production fluid from a well.
Summary of the invention
A method for extraction of fluid from the completed wells in which: (i) as a function of time calculated the expected flow rate of the fluid flowing into the borehole of at least one production zone, in accordance with the first setting of at least one downhole device for controlling the flow rate, which allows fluid from the production zone to flow into the borehole, (ii) during a certain period of time to control the actual flow rate of fluid flowing into the borehole of at least one productive zone in accordance with the first setting of at least one device for controlling the flow rate, (iii) the use of computer models and the set of input data, selected data from downhole sensors, ground sensors, and setting at least one downhole device, ask with regard to the trend of the actual flow rate of at least one second tune is oyku at least one device for controlling the flow rate, when the flow rate of the fluid from at least one productive zone will increase to a level above the expected flow rate of the fluid from at least one production zone, (iv) and perform well operation in accordance with at least one second setting with the aim of increasing production fluid from at least one production zone. According to the method based on the at least one second configuration can be calculated a second flow rate of the fluid over a long period of time of at least one production zone. Then, on the basis of at least one of the second configuration may be calculated net present value (NPV) of the well.
The input data can be selected from the data relating to the pressure in the well, the well production rate, production rate on the surface, the operating parameters of the electrical submersible pump, the flow rate of the injected chemical agents, temperature, resistivity of the strata of rock or fluid density of the fluid, fluid composition, the results of measuring the capacitance of the fluid; vibrations in the borehole, the acoustic measurements in the borehole, the differential pressure in the downhole device, water content, water-oil factor, gas-oil factor and the gas factor. They may also use other data and measurements, including without limitation the results of microseismic measurements, the results of the tests with variable pressure measurements in wells, the measurement results concerning the presence of one or more chemical reagents in the well, which may include sediments, hydrate, corrosion and asphalt. According to other features of the method may calculate the probability of occurrence of one or more events, including water breakthrough, cross-flow, casing wear well or wear downhole device, and then on the basis of such a calculation to set the second setting or settings. Can be other settings to account for changes in flow rate of the injected chemicals, work APN, close the selected production zone, etc. According to other features of the operator in the vicinity of boreholes and / or at a remote location, can be transmitted messages on the second setting. After the implementation of a new configuration of devices can be monitored and evaluated actual production. Then the process repeats itself. The method also provides that on the basis of at least one second configuration update anticipated production fluid from the well or the production zone.
According to other features of the proposed system to increase production rate wells with multiple productive zones, a separate device for regulating the flow rate of the La each productive zone and device for booster production, which includes a computer system having a processor, the computer-readable media for storing computer programs and data available to the computer to execute instructions contained in a computer program, and a display for displaying information transmitted by the processor, when this computer program contains (i) a set of commands over a certain period of time the actual flow rate of fluid from each productive zone in accordance with the first configuration of each device to regulate the flow rate and the flow through the device for tubing production; (ii) a set of commands to apply the circuit analysis method of nodal potentials to the set of input data, including data from borehole sensors, data of ground-based sensors, the current position of at least one device for regulating the flow rate that, given the tendency to decrease the actual flow rate to set the new setting at least one device for controlling the flow rate to increase well production, and (iii) a set of commands to continue to monitor the increased flow rate corresponding to the new configuration.
Examples of a system and method for monitoring the physical condition of the equipment wells and the regulation of the flow rate stated in quite General terms will be disclosed in SL is blowing forth a detailed description for a better understanding of how their and additional features in the claims.
Brief description of drawings
To ensure a detailed understanding of the systems and methods of control and regulation of the rate of production wells, described and claimed in the invention, one should refer to the accompanying drawings, in which similar elements are usually denoted by the same positions and in which is shown:
figure 1 is a high - level block diagram of a closed-loop control system (monitoring) and control wells according to one feature of the invention,
on figa and 2B is a schematic depiction of a system of exploitation wells for the extraction of fluid from multiple productive zones according to one possible implementation,
figure 3 is an example block diagram of a control system that can be used in the system of exploitation wells, including the system shown in figa and 2B, to carry out various measurements relating to the well, determine the desired actions that can be taken to increase well production, automatic execution of one or more of such actions, predict the effect of such actions and behavior monitoring wells after taking such action,
figure 4 - example of the curve of change of pressure over time in a productive well such as, for example, p is cousin to figa and 2B, in accordance with one feature of the invention is applicable to control the flow rate of the well,
figure 5 is an example graph illustrating the expected behavior of wells, such as shown in figa, and the actual behavior of such wells, as well as examples of relevant moments when described in the invention, the system can perform one or more of the required actions, and behavior well after taking such action, and
figure 6 is a functional block diagram illustrating the software behavior analyzer wells, 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.
Figure 1 shows a high-level block diagram of a system 1 production, which includes the cycle or system 1A of increasing and optimizing production of a specific well, combined with the system or cycle 1B optimizing the operation of a reservoir or field. Before starting the development of the field with the aim oil and gas, create a model or cycle 1B. The implementation and updating cycle 1B is a relatively lengthy process and is intended to optimize the exploitation of the Deposit. Cycle 1B may include a plan 7 development with the location, depth and type of wells to which e must be drilled. The plan is usually based on the geological and physical characteristics of the layer 6, which can used data from different sources, including seismic data (two-dimensional or three-dimensional map data, other deposits in the region; analysis of rocks on the subject of potentially productive formations, etc. using economic analysis to develop the programme 8 capital investment in drilling and completion of wells in the field. On stage 9 of the plan, perform and update, based on information about the behavior of wells.
According to one feature of the cycle 1A is a vicious cycle that can be designed to increase or to maximize production from a particular well in the field. During cycle 1B system well control continuously monitors or measures various parameters of the 2 wells that include the parameters in the borehole and at the surface; continuously performs diagnosis or analysis of 3 a variety of data, including historical data on wells and the results of current measurements, coming from a variety of downhole and surface sensors, using programs, models and algorithms developed for system 1B; and creates a plan 4 action when the results of the analysis indicate that the flow rate is outside the selected or gelatelno the range. Plan 4 action can contain the proposed operator action to change one or more parameters of a well, such as changing the flow rate of the one or more zones, changing the flow rate of the injected chemicals or changing work APN etc.
According to one feature after the operator will perform one or more actions, well continue to monitor through the system or cycle 1A, calculate the effect of implemented actions on the well production rate and other parameters and continue to review and, as necessary, to transmit messages to the operator. According to other features of the system 1B may be designed for automatic intervention (stage 5) and implement or oversee the implementation of one or more actions. It can be initiated, if the operator does not carry out any act or perform inappropriate actions, or if the status of the well is the basis for certain actions, which may include any of the actions proposed by 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 implement any action, including the cessation of production from any zone wells or discontinuance of elektricheskogo submersible pump, injection of chemical reagents, etc. the system or loop 1 with reference to one example of a borehole are described in more detail with reference to figures 1-5.
On figa and 2B schematically shows a system 10 well operation according to one embodiments of the invention. On figa shows a production well 50, the feature is shown as an example of the equipment, devices and sensors that can be used to implement the described invention ideas and methods. On figb shown, for example, ground equipment, devices, sensors, controllers, computer programs, models and algorithms that can be used to control and maintain, increase, optimizing or maximizing the production rate of the well 50. According to one feature of the system 10 is designed for intermittent or continuous use of the results of measurements coming from different sensors, and other data to determine the behavior of the well, including the flow rate of each productive zone, the status of the various devices of the system 10, the prediction of the behavior and condition of the well 50 and its corresponding equipment, including sand, water flow, water breakthrough, cross-flow, the position of the water front and the status of various devices, etc. According to other features of the system 10 m which may be calculated to determine the necessary actions, which can be made for increasing or maximizing well production 50 according to the selected criteria. According to other features of the system 10 may be designed to transfer to the operator and(or) other locations desired messages and warning signals regarding the status of the wells and the necessary adjustments or actions relating to the various operating modes of the bore 50, to commit one or more of the following: regulation, increasing, optimizing or maximizing well production; mitigate or eliminate the negative impact of potential or actual occurrence of a hazardous condition, such as the accumulation of certain chemicals, such as deposits, corrosion, hydrates and asphaltenes, potential or actual water breakthrough, cross-flow or wear certain equipment, etc.
According to other features of the system 10 can be configured to provide control actions taken (if it occurs) by the operator in response to the message sent by the system; update any action after adjustments made by the operator; implementation of selected adjustments, if the operator to take certain actions; automatic management and control of the ü one or more devices or equipment of the system 10; and reporting on the state of the operator and other addresses, including one or more remote points. According to other features of the system 10 may be designed to establish two-way communication with one or more remote access points or controllers via one or more respective data lines, including the Internet, a wired line or a wireless connection, and using one or more appropriate protocols including Internet protocols.
On figa shows a hole 50 drilled in the thickness of the 55 species for production of reservoir fluids 56a and 56b of the two (for example) productive zones 52a (upper productive zone) and 52b (lower producing zone), respectively. It is shown that the well 50 is fixed casing 57 with perforations 54A near the upper productive zone 52a and perforation holes 54b near the lower production zone 52b. Packer 64, which may be a removable packer located above or higher in the wellbore than the perforations 54A, isolates the lower production zone 52b from the upper productive zone 52a. Near the perforation holes 54b can be installed filter 59b to prevent or deter the ingress of solid particles such as sand in the style of the well from the lower production zone 54. Similarly, near punch hole 59A of the upper productive zone can be used filter 59A to prevent or deter the penetration of solid particles into the well 50 of the upper productive zone 52a.
Wireline fluid 56b of the lower production zone 52b through the perforations 54A enters the annular space 51A of 50 wells and booster casing 53 through the control valve 67 of the flow rate. The control valve 67 of the flow rate may be a remotely controlled spool valve, or any other applicable valve or fitting, which is capable of regulating the flow of fluid from the annular space 51 in production tubing of the column 53. To regulate the flow of fluid from the lower production zone 52b on the surface 112 in the tubing string 53 can be used adjustable fitting 40. Wireline fluid 56 from the upper productive zone 52a through the perforations 54A enters the annular space 51B (section annular space above the packer 64A). Wireline fluid 56 through the inlet 42 enters the operational tubing column or line 45. Adjustable valve or fitting 44 that is associated with the line 45, regulates the flow rate of fluid through the line 45 and may be used to regulate the flow rate of flue is a, coming to the surface 112. Each valve, fitting or other such device in the borehole 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 eject fluid 56a and(or) fluid 56b on the surface for lifting fluids from a well to the surface 112 may use equipment for mechanized (booster) production, such as electric submersible pump (APN) or gas-lift system. As the equipment for the booster extraction system 10 is shown mounted on the manifold 31 APR 30 that receives reservoir fluids 56a and 56b and which through a system of 47 pipes pumping fluids to the surface 112. Cable 134 in EPN 30 is energized from a terrestrial source 132 power (figb), which manages the block 130 control APN. The cable 134 may also have bilateral lines 134a and 134b data, which may represent one or more electrical conductors or fiber optic cable, duplex line exchange of signals and data between APR 30, the sensors SEAPN and block 130 control APN. According to one feature of rabota APR 30 controls unit 130 controls APN. Block 130 control EPN can be a computer system that may include a processor, such as microprocessor, memory and software for analysis and control EPN 30. According to one feature, the controller 130 receives data from the sensors SE(figa) signals related to the actual frequency of the pump discharge, performance APN, pressure and temperature of the fluid in EPN 30, and can take measurements or data relating to certain chemicals, such as corrosion, deposits, asphaltenes, etc. and to respond to them or other calculations to manage work APR 30. According to one feature of the block 130 control EPN can be designed to change the speed of APN by transmitting control signals 134a in response to data received on line 134b, or commands received from the other controller. Block 130 control APN also may stop power supply in APN on line 134 power. According to another particular unit 130 controls APN can pass on APN data and information (frequency, temperature, pressure, data on chemical sensors and so on) of the Central controller 150, which in turn can transmit control signals or commands to the block 130 control APN to ensure the selected modes APN 30.
To control the discrepancies between the different devices in the borehole 50 and obtain measurement results and other data from various downhole sensors in the well 50 is laid a variety of hydraulic, electric lines and data lines (generally indicated by the position 20 (figa)). For example, the system 21 of the pipes from the surface of a specific chemical reagent may through mandrel 36 fed or introduced into the fluid 56b. Similarly, the system 22 pipes-specific reagent can through mandrel 37 fed or introduced into the fluid 56 in production tubing string. Lines 23 and 24 can be used to control any other device such as a valve 67. Line 25 may be used to supply electricity in some downhole device from the corresponding ground power source. Two-way data link between the sensors and their associated electronics (generally indicated by the position 25A and located in any one or more of the relevant provisions in the well) can be installed in any desired way, including, without limitation, wire, fiber optic, acoustic telemetry communication channel with hydroline; electromagnetic telemetry, etc.
According to one feature in the relevant provisions in the well 50 are a variety of other sensors for transmission measurements or information relating to the number of interest downhole parameters. According to one of the features is it in production tubing string may be located one or more holders of measuring devices or sensors, such as the holder 15 to accommodate any number of relevant sensors. In the holder 15 can accommodate one or more temperature sensors, pressure sensors, sensors for measuring the flow rate sensor for measuring the resistance of the sensors that transmit information about the density, viscosity, water content or water cut, etc. and chemical sensors that transmit information about the deposits, corrosion, asphaltene, hydrates, etc. the Sensor density can be an apparatus for measuring the density of the fluid coming from each production zone, and the density of the combined fluid from two or more productive areas. The resistance sensor or other suitable sensor can perform measurements associated with water content or water content of the mixture of fluids coming from each production zone. For the calculation of oil-water factor and gas factor for each productive zone and the joint fluid can be used with other sensors. Temperature sensors, pressure and flow rate perform measurements of temperature, pressure and velocity of fluid through the line 53. For measurement of pressure, temperature, speed of supply of the fluid and the water content in the reservoir fluid received from the upper productive zone 52a, you can use the additional holders measuring the output devices. To perform measurements related to the chemical characteristics of the downhole fluid, such as paraffin content, hydrate, sulphide, sediments, asphaltene, emulsions, etc. can be used for more downhole sensors in other desired positions. In addition, in the well 50 may be permanently installed sensors Si-Smfor the implementation of acoustic or seismic or microseismic measurements, measurements of reservoir pressure and temperature, measurement of resistivity measurements of the properties of casing 51 and a thickness of 55 species. Such sensors can be installed on the well casing 57 or between the casing 57 and thickness of 55 species. In addition, the filter 59A and(or) filter 59b may be covered by the indicator substances, which are released in the presence of water that can be detected on the surface or in the borehole and allows to detect or predict water breakthrough. On the surface can also be installed sensors, such as, for example, a sensor for measuring the water content in the incoming fluid, the total volume of incoming fluid, the wellhead pressure of the fluid, temperature, etc., Other devices can be used to calculate the sand for each zone.
In General, in the well 50 may be appropriately placed enough sensors to implement the Oia measurement for each desired parameter, of interest. Such sensors may without limitation include sensors for measuring the pressure in each productive zone, the pressure for the selected section of the wellbore, the pressure inside the pipes for supplying the reservoir fluid pressure in the annular space; sensors for measuring temperature at selected points throughout the borehole; a sensor for measuring the flow rate of fluid in each of the productive zones, the total flow rate, performance APN; sensors for measuring temperature and pressure in APN; chemical sensors for transmitting signals on the accumulation of chemical reagents, such as hydrates, corrosion, deposits and asphalt; acoustic or seismic sensors for measurement signals generated on the surface or in adjacent wells, and signals associated with the migration of fluid from the injection wells or fracturing operations; optical sensors for measuring chemical composition and other parameters; sensors for measuring various characteristics of the strata of rocks surrounding a borehole, such as resistivity, porosity, permeability, density of fluid, etc. Sensors can be installed on the tubing in the borehole or on any device, or can be permanently installed in the well, for example, on the casing of the well, on the barrel with the vazhiny or between the casing and wall. The sensors may include sensors of any appropriate type, including electrical sensors, mechanical sensors, piezoelectric sensors, fiber optic sensors, optical sensors, etc. Signals from the downhole sensors may be partially or fully processed in the wellbore (as, for example, a microprocessor and associated electronics, is able to exchange signals or data from downhole sensors and devices), and then transmitted to the ground controller 150 through the transmission line signals/data, such as line 101. The signals from the downhole sensors can also be transmitted directly to the controller 150.
As shown in figb, the system 10 further comprises a ground unit 120 for injection of chemicals for feed additives a into the well 50 and additives 113b in ground unit 170 cleaning fluid. The desired additives a from the source 116A (such as a reservoir) can build up in the bore 50 via pressure lines 21 and 22 through the corresponding pump 118, such as a reciprocating positive-displacement pump. Supplements a flow on the lines 21 and 22 and flow into the reservoir 30 and 37. For feed additives in different productive zones can be the same or separate discharge line. Separate discharge line, such as lines 21 and 22 allow the OS is to conduct independent injection of different additives at different depths in the borehole. In this case, to store and discharge the desired additives used different sources of supplements and pumps. Additives can also be introduced in onshore pipelines, such as line 176, or surface treatment and processing facility, such as block 170.
The corresponding flow meter 120, which may be a designed for low flow rate precision flow meter (such as a flowmeter gear type or rotary flowmeter that measures the flow rate of fluid in the lines 21 and 22 and transmits the signals reflecting the relevant rates of flow. Pump 118 controls the corresponding device 122, such as an engine, or driven by compressed air device. The stroke of the pump and / or the speed of the pump can be regulated by the controller 80 through setting circuit 92 and the line a management. The controller 80 may control the pump 118 by using programs stored in the memory 91, associated with the controller 80 and / or 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 through appropriate bilateral line 85, which may be a wired, fiber optic or wireless connection, and using one or more of sootvetstvujushij 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 measuring the flow rate of the device taken on line 121, and a program stored in the memory 91 to determine the consumption of each of the additives, and displays the performance of such consumption on the display 81. The sensor 94 is able to provide information about one or more pump parameters such as the speed of the pump, the stroke length of the piston, etc. for Example, the speed of the pump or the stroke length of the piston can be increased when the measured amount of injection of the additive is less than the desired number, and reduced when the injection quantity is larger than the desired number. The controller 80 also contains schemes and programmes, generally indicated by the position 92, for interoperability with local display 81 and to perform other desired functions. The sensor a level provides information about the remaining content source 116. Alternatively, the Central controller 150 may transmit controller 80 team regarding discharge supplements, or may perform the functions of the controller 80. Although figa-2B illustrate one production well, it is understood that in the oil field can be there are many wells, and could the t to be located in a variety of wells, such as neighboring wells, injection wells, test wells, etc. devices shown in the drawings, can be used on any number of such wells and can be configured for collaborative or independent work.
Figure 3 shows a block diagram of example system 200 well operation, which can be used to control zoom, optimizing or maximizing well production and to optimize operation of the reservoir. The system 200 includes a Central control unit or controller 150, which includes one or more processors, such as processor 152, the corresponding storage device 154 and the corresponding circuit 156, designed to implement the various described in the invention functions and methods. The system 200 includes a base 230 of the data stored on the corresponding machine-readable medium accessible to the processor 152. In the data 230 may include: (i) data and information on well completions, as, for example, the types and locations of sensors in the borehole, the sensor parameters, the types of devices and their parameters, such as the type and size of fittings, the provisions of the fittings, the type and size of valves, valve position, the wall thickness of casing pipes etc; (ii) formation characteristics, such as the type species for the different layers of the reservoir, porosity, permeable is here, mobility, resistivity and depth of each layer and the production zone; (iii) the parameters of sand filters; (iv) information about the indicator substances; (v) the parameters APN, such as power, frequency range, and the ranges of operating pressures and temperatures; (vi) the behavior (performance) well for the last period, including the flow rate over time for each production zone, the pressure and temperature over time for each production zone; (vii) current and previous settings fittings and valves; (viii) information about the intervention and maintenance; (ix) the data content of sand and water over time for each production zone; (x) the original seismic data (two - or three-dimensional maps) and updated seismic data (four-dimensional seismic maps); (xi) data control front water; (xii) any other information that may be useful for monitoring and increasing the flow rate of the well 50.
During well operation is usually carried out one or more tests, collectively indicated by the position 224 to calculate the degree of health of the various elements of the well and the various parameters of the productive zones and layers of the formation surrounding the borehole. Such trials may without limitation include verification of casing pipes and the use of electric or acoustic probes; testing private wells, which may include tests with high or variable pressure, tests on heat flow, seismic studies, in which source can be used on the surface and the seismic sensors in the borehole to determine the state of the water front and boundary layers; microseismic measurements, such as testing after fracturing operations or water injection; control assay front fluid; tests on secondary production, etc. All data 224 such tests can be stored in memory and transmitted to the processor 152 to control the flow rate of the well 50, carrying out analysis concerning the increase, optimizing or maximizing well production 50 and optimizing the operation of the reservoir.
In addition, the processor 152 system 200 may periodically or continuously access data 222 measurements downhole sensors, data 226 ground-based measurements and any other desired information or data 228 measurements. Data 222 measurements downhole sensors include, without limitation data of water content or water cut, resistivity, density, viscosity, sand content, flow rate, pressure, temperature, chemical properties or composition of fluids, gravity, slope, results of electrical and electromagnetic measurements, gas and water is the oil of factors fluids and regulations fittings and valves. Data 226 ground-based measurements include, without limitation, the data of flow rate, pressure, regulations, fittings and valves, parameters APN, calculations of water content, velocity and location of the discharge of chemicals, data detection indicator substances, etc.
The system 200 also contains programs, models and algorithms 232 embedded in one or more machine-readable media accessible to the processor 152 to execute the commands contained in the programs. The processor 152 may use one or more programs, models, and algorithms to perform the various described in the invention functions and methods. According to one feature of the program/model/algorithms 232 can be implemented in the form of a behavior analyzer wells (APS), which is used by the processor 152 to analyze some or all of the data 222, 226 measurement data 224 trials, information from the database 230 data and any other desired information, which receives a processor for calculating or predicting one or more operational parameters of the well.
According to one feature of the processor may be configured to determine the rate of fluid from each zone, such as shown in figa zone 52A and B, and the total flow rate, compared to the national rate with the expected performance debiti act, when the actual flow rate falls below the expected level, as shown in block 260. As noted earlier, in the initial stages shown in figure 1 cycle 1B optimizing the operation of the reservoir creates a plan of expected production of the well. Figure 5 shows a diagram 500 illustrating a curve 510 hypothetical expect a decline in production of the well 50. Curve 510 decline shows the dependence of the expected oil production rate plotted on the vertical axis and the duration of extraction (in years)plotted on the horizontal axis. Curve 550 displays the actual performance of the well 50. In the beginning of the countdown well commissioning and start producing at the level 552, with production exceeds the expected level until it falls below the expected level at the moment 556.
APS analyzes the data using the measurement results of one or more sensors, the data from the database and test data, as well as the current settings of various devices to regulate the flow rate, and determines the actions, the implementation of which is expected to increase well production rate to the expected level or levels higher than expected. To identify actions that can be taken to increase well production, APS uses models, programs, and algorithms. To this end, the APS t is the train can use the circuit analysis method of nodal potentials and can expect higher production levels after the specified actions have been implemented. The processor transmits to the operator and the remote controller 185 messages 262 containing the proposed action. The processor may also periodically or predominantly continuously display certain information on the display 262 for use by the operator and(or) remote controller 185, such information may without limitation include data extraction from each zone, the data of the current settings of valves and fittings, data frequency and performance APN, data accumulation of chemicals in the well, the water content for each zone, etc. of the Proposed action may include changing the frequency APN, changing the flow rate of the injected chemicals, changing the settings fittings and valves etc. APS can also expect the estimated effect of one or more proposed changes to the mining and the impact of cumulative changes. In some situations, it may be desirable to reduce the production from one zone to increase production from other zones. According to one feature, the processor waits until the operator does not effect the proposed changes. If the operator does not do these steps, the processor may send reminders and send messages in the deleted items including emails. As soon as the operator carries out the proposed action, the production is acinet grow until 558, and then begins to fall until 560. According to one feature of the APS may be designed not to expect a decline below the expected level appropriate to the moment 556, and to extrapolate on the basis of the curve of decline and send the operator a message with instructions to perform one or more specified processor action, the operator can advance to react and to maintain production at a higher level. Subsequently, the well productivity may fall below the expected level, as in the above example, additional steps are carried out at the moment 562, does not lead to increase oil production up to a level higher than expected, so it may be desirable to carry out the extraction of secondary methods. The processor 152 may display on the display for the operator is shown in figure 5 charts. The results of the performed analysis can be transferred to the remote controller 185, which may use such information to update the model geological and physical characteristics (cycle 1B, figure 1). Illustrated in figure 5, the example corresponds to the scenario according to which actual production exceeds the expected production based on the original model. In other situations, the actual production can begin with lower rates and may not p is avisat anticipated production rates. In any case, can be applied to the above-described method.
According to other features of the results of the performed APS analysis can follow that to increase or optimize well production, such as the well 50, more preferably to carry out the production from one zone until the water content does not exceed the selected value. In other words, it may be desirable to carry out the production from one zone until the sensor readings watering will not exceed the limit of the productive life of the well and its equipment. Then, the system 200 overlaps the first area, opens the second zone, and the extraction fluid is carried out as described above until it is profitable.
According to other features of the system 200 can predict the characteristics of the process of production fluid from the well and to adjust the characteristics of the wells with the aim of optimizing or maximizing well production. For example, the APS can predict water breakthrough or the occurrence of the cross flow or wear any device or casing pipes, etc. to determine the necessary actions to transfer the message to an operator, as described above, the necessity to change the characteristics of the well or may automatically carry out such actions.
For example, the APS can determine the source or sources of water breakthrough ka is, for example, location in a productive zone, the location in the strata of the rocks above and / or below the production zone; cracks in the cement binder between the casing and the thickness of rocks; the location of the water front is relatively well etc. APS can also determine the degree or severity of the expected breakthrough of the water and the expected time or period of time, may occur when water breakthrough. To determine the breakthrough of waters of the Central controller 150 may calculate a specific target (such as water content, water content, etc.)concerning the formation fluid (for each zone and(or) total flow rate), for a certain period of time and to calculate or to predict the likelihood of a breakthrough of water using these estimates of water. The controller 150 can use the trend associated with an indicator of water for a certain period of time, or to use in real or near-real-time estimates of water to detect and / or predict the likelihood of a breakthrough of water. Indicator water in reservoir fluid may be specified by the analyzer on the surface, which determines the water content or water content of the produced fluid 224. Indicator water may without limitation include the number, water content in percent, the maximum value, the value of var is in values, etc. Indicator water or the water content of the reservoir fluid can also be calculated on the basis of readings of the downhole sensors (such as sensors, resistivity or density); analysis of indicator substances present in the produced fluid in the well or on the surface; the results of the density measurement; or evidence of any other relevant sensors. According to other features, the processor may predict the likelihood of a breakthrough of water by using the results of the acoustic measurements made permanent downhole sensors, or the results of microseismic measurements or four-dimensional seismic maps showing the front water-specific productive zone, or on the basis of cracks in the rock, accompanying a productive zone. The processor can also predict the location and extent of water breakthrough on the basis of the calculation of the casing wear according to the control casing or on the basis of the wear of the cement binder. According to one of features to determine a desired action, the Central controller uses the proactive model or a neural network. These models can, for example, be used to assess the efficiency of the one or more actions, costs associated with the implementation of one or more actions for the implementation of a comparative analysis of two or more of such actions, etc.
After the Central controller 150 predicts the potential breakthrough of the water, it defines the actions that need to be taken to mitigate or eliminate the negative effects of water breakthrough and how it is possible to optimize production. The Central controller 150 may recommend to block specific productive area by closing the valve or fitting; to cover all areas; close fitting on the surface; reduce the production of fluid from a particular area; to increase the production of fluid from unaffected areas, change the frequency APN or off APN; change the flow rate of the injected chemical agents in the area, etc. of the Central controller 150 transmits the recommendations to the operator. If water breakthrough concerns only one of all zones, the system may recommend extraction of fluid from the potentially affected area up to a certain point, and then to cover this area prior to the occurrence of the water breakthrough. Alternatively, the system can recommend to reduce the production from one zone and continue production from other zones, or in some cases, the system may recommend to increase production of one or more other zones. According to one feature of the APS in each case may determine the combination of actions that are likely to maximise the flow rate until it is stopped for repair.
As described above, the processor transmits a message to an operator indicating to perform the desired actions, 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 carried out by operators, similar to that described above with reference to figure 5. After the operator makes a change, the Central controller 150 continues to process the data flood and continues to operate as described above. According to another particularly when the Central controller 150 detects threatening a breakthrough of water or alarming situation, he may initiate one or more desired actions.
According to another particular hydrocarbon production can be increased by reducing water withdrawals from productive zones on the basis of selected criteria. APS can determine the production rates of the various zones, which will reduce water withdrawal from wells, but will be maintained or will increase the production of hydrocarbons from the well. According to one feature of the APS determines that such production levels, which is also supported by the pressure at a desired level or in a selected range. Then the TSA specifies settings of valves and fittings, frequency, or power APN and the flow rate of the injected chemicals. - % The SOR sends the operator and the remote controller messages and performs other functions like as is described above.
According to other features of the system 200 may contribute to changes in the production in case of detection or prediction of the transverse flow. In normal operating conditions of the well 50, the pressure in the lower productive zone V exceeds the pressure in the upper productive zone 52a. In such conditions wireline fluid 56 from the upper productive zone will take place in the surface direction, as indicated by arrows 77A. However, under certain conditions, the pressure Pu in the upper productive zone 52a can begin to grow and subsequently exceed the pressure "Pl" in the lower productive zone W. As this shift of wireline pressure fluid from the upper production zone begins to flow towards the lower production zone. At a certain point in time, the pressures Pu and pressure Pl intersect. In such a scenario, it may be impossible to maintain the production of reservoir fluids 56a and 56b of the bore 50, and can cause damage to one or more downhole devices, such as EPN 30 and the wellbore as a whole. According to one feature of the Central controller 150 continuously calculates pressure Pu and Pl, and uses the model or program to predict the occurrence of intersection, and determines one or more actions that should be osushestvleniu response to detection of the transverse flow. APS may contain one or more models and / or algorithms, which may be based on data for the last period or laboratory data, or other synthesized data to determine the expected time of occurrence of the crossing. Models may take into account any number of factors, such as the percentage by which the well pressure exceeds the formation pressure, and duration of existence of such condition; the rate of change of pressure Pu and Pl; the difference of the pressures Pu and Pl, temperatures in the upper and lower producing zones; larger than the pressure in the annular space (upper zone) pressure tubing (lower zone), and open the area for extraction of fluids; and when the results of the downhole flow measurements indicate that the flow approaching the cross flow; and any other desired factors. The Central controller also calculates the severity and timing of potential cross flow and defines actions that should be implemented. The Central controller may send a warning or alert signal simultaneously with the recommendation of the one or more actions, including, without limitation, recommendations: to close or partially close a particular fitting, such as fitting 40; block or in order to keep the flow of formation fluid 56a on line 45; to close the spool valve 67; change the speed (frequency) APN 30 or disable APN 30; change the number of additives a or 113b, injected into the bore 50, and the ground unit 170 processing; to block or isolate a specific area; to reduce the pressure on the surface; open ground fitting; to reduce the flow through the particular fitting or close specific fitting; and any other applicable recommendation. According to one feature of the recommended actions can represent the optimization of well production. The Central controller 150 continues to monitor describes the characteristics of wells to continuously assess the impact of the changes made by the operator, and continues to provide additional input and recommendations just as described in the invention.
According to other features of the system 200 may recommend or take any action based on the degree of serviceability of equipment. For example, the system 200 can measure the corrosion or accumulation of deposits on any device, such as a valve, or to establish that APN works outside of the specified parameters, or to measure the wear of the casing or cement binder, etc. in response to set an action plan that can ensure optimal net present value of the well. Then, the system 200 is udaetsya implement the plan mainly described above.
According to another features of APS can analyze the data in order to reduce or minimize the removal of sand from each production zone. According to one feature of the processor 152 can control the amount of sand carried from each zone, and by using a circuit analysis method of nodal potentials to predict the sand from each zone. The processor may control the pressure in each productive zone and proceeding from him, and(or) using other data to calculate the sand or anticipated removal of sand from each production zone. Then, the controller determines the appropriate actions, the implementation of which will be reduced to sand and(or) increase the production of hydrocarbons. Actions may include reducing the production of the affected areas, increased production from other zones, the cessation of production from the affected area or any combination of them. Then the MTA passes the message to an operator through a display of actions. The steps may also include changing the speed of APN and changing the flow rate of the injected chemicals to account for changes in production from different zones. The system 200 continues to monitor the impact of changes made by the operator, and can also be designed to transition to automatic mode to automatically initiate any action.
The agreement is but the other features of APS can be calculated on the analysis of the data state variable pressure and calculation of production from each zone, and adjustment of equipment with the purpose of increasing, optimizing or maximizing well production. Figure 4 shows a diagram 400 illustrating an example of change of pressure over time, where the vertical axis represents pressure, and the horizontal axis represents time. Shows the pressure curve corresponds to the period after the productive area was closed. The pressure to close is usually mostly constant. When closing the productive zone pressure slowly begins to grow within a short period of time, such as the period ending at time 412, then mainly grows at a constant rate, as indicated by section 414, after which smoothly changes as indicated by section 416. APS analyzes the data variable pressure and sets the various downhole devices in the system 10 to increase well production, based on selected criteria, and sends the new settings to the operator or automatically installs a new device setup and then continues to monitor the impact of the new settings and to provide feedback as described above.
According to another features of APS can analyze test data well and set new parameter extraction and appropriate new settings. According to the other features of APS can expect the presence and(or) the rate of accumulation of chemical reagents, such as deposits, corrosion, hydrates and asphaltenes, and can expect their influence on the rate of extraction and the degree of serviceability of certain devices, such as valves, fittings, APN and piping systems. APS defines actions and sends the appropriate message to the operator and in remote settlements and performs tracking functions described above. Actions may include changing the flow rate of the injected chemicals, changing the speed of APN, changing the flow of the one or more zones, removing components, valves and fittings to clean from corrosion or deposits, etc.
In some situations, various options and settings can be interdependent. For example, if the decrease in production from one zone by installing the fitting in position less bandwidth may change the pressure in the well and the flow rate of the other areas, and may require a different setting APN and different flow rate of the injected chemical agents, etc. as another example, the cessation of production from one zone can provide the desired increase in hydrocarbon production, but can cause damage APN, because when reducing the speed of its work to a level consistent with the rate of production, APN may go beyond the specified technical requirements. In this case, it may be desirable to e who H worked with better performance and selected a small portion of the fluid from the zone, which was originally selected for closure. According to one of the features in any of the scenarios described above APS defines actions or settings on the basis of compliance with the selected criterion or criteria in order to enhance, optimize or maximize well productivity. APS can perform a circuit analysis method of nodal potentials or to use preemptive model, enabling configuration of the various devices.
Figure 6 shows the functional block diagram 600, the APS 610 performs circuit analysis method of nodal potentials, uses neural network and(or) other proactive model to set various operating parameters, such as setting of various devices, and to increase the flow rate with a specific configuration. According to one feature of the APS 610 receives the data of ground-based measurements or the results of calculations on the basis of ground-based measurements 612, downhole measurements or the results of calculations based on downhole measurements 620, data 614 tests, information from the database data 616 and any other information 618, which may be relevant to a particular well, and uses the circuit analysis method of nodal potentials and(or) other proactive model to specify new settings. The circuit analysis method of nodal potentials can in order to enable prediction of the effects of the new settings on the production and the iteration of this process, until there is a new combination of settings (final plan), which will increase, optimization, or to maximize the production rate of a particular well. According to one feature may include or not include the impact of the plan on production at the field. According to other features of the circuit analysis method of nodal potentials may be based in part on the analysis of net present value, so that the new settings have increased the expected total net present cash inflows from production wells, as shown in block 650. APS is trying to carry out the steps described above.
As shown in figb, 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 the selected devices, such as controller APN to adjust APN 242; control units or drives (160, figa and element 240), which control the downhole fittings 244, downhole valves 246, ground fittings 249, unit 250 controls the injection of chemical reagents, other devices 254, etc. Such actions may be taken in real or almost real time. In step 264, the Central controller 150 continues to con the exercise of their results of their actions. According to another features of the Central controller 150 or the remote controller 185 may be configured to update one or more models/algorithms/programs 234 for further use with the aim of monitoring wells. Thus, the system 200 may, in closed loop mode to control the behavior of the well, to perform or to procure the realization of the desired action and continue to monitor the results of such actions.
Although the above description discusses several examples of implementation and the methods for professionals in this area of technology will be obvious enhancements. It is assumed that all such improvements included in the scope of the attached claims, included in the foregoing description.
1. The method of production fluid from the well, in which:
calculate the expected trend of the flow rate of fluid as a function of time, of at least one production zone of the well when you first set up at least one downhole device for controlling the flow rate;
monitor the actual flow rate of fluid from the mentioned at least one productive zone in accordance with this first configuration, at least one device for regulating the flow rate;
estimate the probability of occurrence, on ENISA least one of the events, including the breakthrough of the fluid cross-flow, casing wear well and wear well device;
using computer models and the set of input data, selected data from downhole sensors, ground sensors and the parameters of the said at least one downhole device for controlling the flow rate, set, based on the trend of the actual flow rate that is different from the trend of the expected flow rate of the fluid, at least one second mentioned configuration, at least one device for regulating the flow rate at which the expected change of the actual flow rate of fluid from the well to the level determined by the trend, the second configuration set on the basis of these probability scores; and
configure the downhole equipment in accordance with said at least one second configuration to provide increased production fluid from the well.
2. The method according to claim 1, wherein on the basis of at least one second configuration to further define well the second expected flow rate of the fluid over time.
3. The method according to claim 2, which calculates the net present value for a well on the basis of the second expected flow rate of the fluid.
4. The method according to claim 1 in which the said multiplicity Yes the data is chosen from the group including data relating to the pressure in the well, the well production rate, production rate on the surface, the operating parameters of an electric submersible pump (APN), flow injection chemical reagents, temperature, resistivity, density of fluid, fluid composition, measurements capacitance, vibration, acoustic measurements, differential pressure device, water content, water-oil factor and gas factor.
5. The method according to claim 4, in which said group further comprises at least one of the following data: data of the microseismic measurements, the results of the tests with a variable pressure, the results of well logging measurements in the borehole and the measurement data concerning the presence of downhole chemical substances belonging to one of the substances, including deposits, hydrates, corrosion products, asphalt and paraffin wax.
6. The method according to claim 1, which further modifies at least one parameter relating to the flow rate of the injected chemicals, work APN and closing of selected production zone, if the well has many productive zones.
7. The method according to any one of claims 1 and 2, which further transmit a message relating to at least one second configuration, at least the operator or udalen is coming from the well point.
8. The method according to any one of claims 1 and 2, in which at least one second adjustment involves changing the position of at least one device, changing the flow rate of the injected chemicals and changing the flow rate of the fluid from the downhole device of mechanized production.
9. The method according to any one of claims 1 and 2, in which on the basis of at least one second configuration advanced update expected flow rate of the fluid.
10. The method according to claim 1, in which during a certain period of time additionally control the actual flow rate of the fluid, at least one productive zone in accordance with at least one second configuration, and given the tendency to reduce the actual flow rate after the life of the well, at least when the second setting is set to the third setting, which will increase the flow rate of the fluid, at least one productive zone.
11. System for increasing well production, with many productive areas, a separate device for regulating the flow rate for each productive zone and device for mechanized production, and which includes:
a computer system comprising a processor, the computer-readable media for storing computer programs and data with access to a computer to perform content is working in a computer program commands, and a display for displaying information transmitted by the processor, when this computer program contains:
the set of commands for calculating the expected trend of the flow rate of fluid as a function of time, of at least one production zone of the well when you first set up at least one downhole device for controlling the flow rate;
the set of commands for monitoring for a certain period of time the actual flow rate of fluid from each productive zone in accordance with the first configuration, at least one device for regulating the flow rate and flow through the device for mechanized production;
the set of commands to assess the probability of occurrence of at least one of the events, including the breakthrough of the fluid cross-flow, casing wear well and wear well device;
the set of commands for the application of circuit analysis method of nodal potentials to the set of input data, including data from downhole sensors, data from ground sensors and the current position of the at least one device for controlling the flow rate so that, on the basis of the trend to reduce the actual flow rate that is different from the trend of the expected flow rate of the fluid to set the new setting at least one device for controlling the flow rate to ensure production of well-defined trend, the second configuration set on the basis of these probability scores; and
the command set for continued monitoring of the increased flow rate corresponding to the new configuration.
12. The system according to claim 11, in which the computer program further comprises a command to calculate the expected increased flow rate of fluid for wells based on the new settings.
13. System according to clause 12, in which the computer program further comprises a command to calculate the net present value for a well based on the calculated increased flow rate of the fluid.
14. The system according to claim 11, in which the said set of input data selected from a group comprising data relating to the pressure in the well, the well production rate, production rate on the surface of the working parameter of the electrical submersible pump, the flow rate of the injected chemical agents, temperature, resistivity, density of fluid, fluid composition, measuring the capacitance of the fluid, vibration, acoustic measurements of the differential pressure in the downhole device, water content, water-oil factor and gas factor.
15. System 14, in which said group further comprises data of the microseismic measurements, tests with a variable pressure measurements in wells and metering the deposits, concerning the presence of downhole chemical substances belonging to one of the substances, including deposits, hydrates, corrosion products, asphalt and paraffin wax.
16. The system according to claim 11, in which the computer program further comprises a set of commands that use a selected criterion to define a new configuration.
17. System according to clause 16, in which the selected criterion is at least one of the criteria, including sand, less than the selected value, the supply of water from selected production zone, less than a selected value, no state cross flow, wear downhole device in the selected limits and work APN in the selected range.
18. System according to any one of § § 11 and 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 the injected chemicals and changing the flow rate of the fluid from the downhole device of mechanized production.
FIELD: oil and gas industry.
SUBSTANCE: system includes several tubular elements located in each other with the channels directing the fluid flows from different formations of the well to different channels of tubular elements fixed in the casing pipe by means of packers. Channels are equipped with spool-type gates with control electric drives providing separate movement of fluid flows from different formations through different channels by means of a processor and a fluid parameter measurement sensor installed in each channel and functionally connected to the automatic control processor of the valve in compliance with the information received from the sensor, and further selective mixing of flows in the area of the casing pipe. Tubular elements are fixed in the casing pipe with upper packer, and at their inlets, they are connected to the coupling directing different flows via different channels from different formations, which is connected via a central channel by means of the shank to the extracting device of the product from bottom formation of the well, which is fixed in the casing pipe with lower packer. Unit of separate supply and accounting is connected via a branch pipe to the electric drive of the submersible centrifugal pump, in which a communication cable is placed to control the valves from the electric feed and control cable, which attaches the pump electric drive to the well electric feed and control station.
EFFECT: increasing operating efficiency of the well formations.
3 cl, 1 dwg
FIELD: oil and gas industry.
SUBSTANCE: method includes blocking of a perforation interval by means of injection of a blocking liquid and its pushing with a killing fluid to a bottomhole and to a bottomhole area of a bed with simultaneous monitoring of pressure at a well head, gas relief and process settling. At the same time, prior to injection of the blocking fluid, a sand screen is formed by injection of a pulp of quartz sand with fraction of 0.6-1.2 mm in a carrier fluid in two portions with a flow rate of a carrier fluid, the value of which does not exceed the maximum permissible value, defined according to the formula. At the same time the volume of the quartz sand in the first portion of the pulp is calculated in accordance with the formula with further process settling of the well for the time determined according to the formula after injection of the first pulp portion. The volume of the quartz sand in the second pulp portion is taken as equal to the volume of suffosion channels produced in the sand screen. The blocking fluid is a certain composition. The blocking fluid volume is previously calculated according to the formula. Besides, at the moment of completion of blocking fluid pushing, hydrodynamic pressure is determined in a tubing string. Afterwards the process settling of the well is carried out. Further injection of the killing fluid into the well is carried out along the tubing string until it appears at the well head. At the same time the well head pressure is controlled in the annular space of the well by means of gas and blocking fluid relief, providing for pressure at the inlet to the tubing string as permanent and equal to the predetermined hydrodynamic pressure.
EFFECT: improved efficiency of gas well killing.
FIELD: oil and gas industry.
SUBSTANCE: design of low-angle and horizontal wells includes a technical string, an operating string and a lift string. The operating string is cemented above the productive formation roof. The operating string in the productive formation is divided into sections with casing packers, and sections include filter sections and sections of solid pipes. The lift string in the productive formation is equipped with operating packers, installed inside the sections of solid pipes of the operating string and groups of controlled valves equipped with calibrated inlet side holes arranged inside filter sections. A seat nipple is installed at the end of the lift string. Controlled valves and the nipple are made as capable of interaction with control devices lowered inside a lift string.
EFFECT: possibility to control an inflow from isolated sections of a low-angle or horizontal well shaft or their total selective water isolation.
FIELD: oil and gas industry.
SUBSTANCE: development method of heavy oil or bitumen deposit with control of well product extraction involves construction of upper injection and lower production wells with horizontal sections located one above another. At construction of wells their horizontal sections are equipped with filters installed opposite productive formation zones. Inside filter with non-perforated interval in production well there arranged is a shank provided with inlet holes dividing the filter into extraction zones. Besides, shank is equipped on the inner side with a stock with side channels. Inner space of stock is interconnected with inlet of pump lowered to production well on the tubing string with possibility of longitudinal movement of the tubing string together with pump and stock in the shank. Heat carrier is pumped through horizontal injection well with warming-up of the formation by creating the steam chamber, and product is extracted through horizontal production well. Thermograms of steam chamber are taken, the chamber's warm-up state is analysed for uniform heating and available temperature peaks, and considering the obtained thermograms, uniform heating of steam chamber is performed. Before the tubing is lowered to production well, first, stock is lowered with a shank concentrically arranged on it and fixed in transport position with a shear screw. Besides, on the outer side of the shank lower end there installed is heat-resistant packer; after the stock is lowered to production well, lower end of tubing is put on its upper end. Tubing is equipped with a pump. Tubing is lowered to production well till the packer is arranged at non-perforated interval of production well filter; after that, packer is installed by dividing the filter of production well into two extraction zones - initial and final. Uniform heating of steam chamber is performed by supplying the heat carrier through injection well. Penetration of heat carrier and/or formation water to the pump inlet is avoided by controlling the product extraction to the pump inlet from the initial extraction zone. Besides, product extraction volume is reduced in the initial extraction zone where temperature peaks occur. For that purpose, inlet shank holes corresponding to the initial extraction zone are made with reduction of carrying capacity from face to head, and side channels of stock are provided with possibility of alternating interaction with one of inlet shank hole in the initial extraction zone. This is performed by restricted longitudinal movement of pipe string together with pump and stock relative to shank by increasing or reducing the number of connection pipes on upper end of pipe string depending on the distance between inlet holes of the shank. Pipe string is fixed on the head of production well in the required position by means of a face plate on a supporting flange, and shank hole corresponding to the final extraction zone is made in the form of an open stock end.
EFFECT: improving the control of product extraction volume from extraction zones; simpler erection and lower metal consumption on the design.
FIELD: oil and gas industry.
SUBSTANCE: method of fluid extraction from the well is performed in the following way: the first adjustment at least of the first well equipment for fluid production is performed; the first set of input parameters is chosen, which includes at least one parameter referring to serviceability degree at least of one second well equipment and sets of parameters chosen from the group including the data referring to efficiency, pressure, temperature, presence of the chosen reagent, content of water, content of sand and flow rate of injected chemical reagents. The first set of parameters is used to be entered to the computer model, and the second adjustment at least of one first well equipment is performed, which will provide at least extension at least of one second well equipment or increase in completed well flow rate. Also, control system of operation of electric submersible pump is proposed, which contains information storage data base relating to operating range of submersible pump, and processor for adjustment at least of one first well equipment, which has the possibility of using at least one measured operating parameter of submersible pump and information stored in the data base.
EFFECT: invention allows performing the monitoring of well shaft state and serviceability degree of various equipment and taking actions, which will provide increased or optimum production of hydrocarbons from the well.
25 cl, 4 dwg
FIELD: oil-and-gas industry.
SUBSTANCE: invention relates to production of natural gas ad may be used in methane-coal well development. Proposed method comprises perforation of operation string in interval of production bed and its hydraulic fracturing. Thereafter, operation string is flushed. Settled fluid level allows defining initial counter pressure on productive coal bed. Production tubing with borehole pump is lowered into flow tubing, the pump being located under perforation interval. Well head is sealed. Borehole pump is used to reduce fluid level in well annuity space to below perforation interval together with injection of buffer gas therein at initial counter pressure on the bed. Thereafter, feed of buffer gas is interrupted. Said fluid level in annuity space is maintained by means of borehole pump. Inflow of bed fluid is caused by releasing excess pressure of buffer gas from annuity space in control over variation in gas quantitative and/or qualitative composition at well head. Change in released buffer gas composition allows defining the beginning of coal methane from productive bed. Now, rate of buffer gas pressure release is decreased.
EFFECT: higher efficiency of well development.
FIELD: oil and gas production.
SUBSTANCE: proposed method consists in using tubing incorporating borehole pump and packer. Note here that borehole pump is equipped with check valve. Check valve is arranged close to and above the pump on tubing outer side to allow one-way fluid flow from tubing into tube space. Said tube space is filled with process fluid with corrosion inhibitor in required concentration. Pressure in tube space is maintained not exceeding tolerable magnitude by means of electric-contact pressure gage connected to borehole pump control unit. Reagent if injected into tubing from wellhead with tube space gate valve.
EFFECT: efficient injection, safe production of oil or gas.
FIELD: oil and gas industry.
SUBSTANCE: according to the method of oil-gas wells killing on deep water subsea deposits by pumping of certain volume of kill composition together with sea water into the well thus providing creation of killing spout in the well with timeless pressure on formation exceeding formation pressure not less than 1.2 times, as a killing composition, preventing immediate contact of cold sea water with overheated formation fluids and productive stratum of formation, large hydrophobic disperse system is used with density exceeding density of sea water more than 5 times in the volume ensuring in bottom-hole zone of the well creation of spout of large hydrophobic disperse system with height exceeding productive stratum formation opened by perforation not less than 3 times. Mentioned disperse system is a disperse system with volume of 70%, where as disperse medium hydrocarbon liquid is used, this liquid doesn't set solid under temperatures to -10°C, its density is not less than 0.860 g/cm3; as disperse phase a mixture of hard metal balls with diameter within 1-2 mm is used, 50% of this ball mixture volume have fusion temperature well over bottom-hole temperature, and the other 50% of this ball mixture volume have fusion temperature 10°C and more below bottom-hole temperature.
EFFECT: improving reliability of oil-gas wells killing on deep water subsea deposits with excessive temperature and pressure of productive formation.
3 cl, 2 tbl
FIELD: oil and gas industry.
SUBSTANCE: typical well operating equipment can include separator for separation of water from oil, in which the produced mixture of fluid media is obtained and mixture is divided into the corresponding water and oil flows. Water flow can be pumped back to the well. For that purpose, well system for water pumping speed control back to the well can be developed. Group of inventions provides the improvement of well flow control efficiency. Essence of inventions: well equipment designed for receiving fluid medium flows through the first and the second fluid medium flow passage channels is arranged in the well. The above equipment includes flow separation control having the device connected to the first channel and the device connected to the second channel, which are interconnected. Outlet flows in the first and the second channels are controlled by means of the control.
EFFECT: increasing outlet flow in one of the first and second channels in response to increase in outlet flow in the other of the first and the second channels by means of action on one of the above devices to keep constant ratio of outlet flows in the above channels.
16 cl, 6 dwg
FIELD: oil and gas production.
SUBSTANCE: method includes gaslift well operation by adjusting the flow rate of working and produced gas. The withdrawal of produced gas is done by tubing string and additional tubing string. The flow rate of working and produced gas is adjusted by opening and closing of driven shut-off elements in accordance to the control signals. Control signals come from automatic control unit and are generated according to the results of measured values compared with set parameter values. Note that the pressure is measured in the mouth and bottom hole, at the same time the flow rate of produced gas is measured. The flow rate of working and produced gas is adjusted in such a way to provide the specified well operation mode.
EFFECT: increase of well operation efficiency, reduction of level and removal of fluid accumulated in bottom-hole zone, provision of well operation stability.
2 cl, 1 dwg
FIELD: mining industry.
SUBSTANCE: invention can be used in case of gas-lift operation of wells equipped by free piston-type installations. Invention envisages stopping well, connecting tube space and annular space in wellhead, recording bottom zone and wellhead pressures in tube and annular spaces, and computing well operation parameters using inflow curve plotted according to differences of bottom zone and wellhead pressures. Volume of produced fluid is found from potential output of formation and from condition of output of free piston. When comparing these volumes, parameters of well are computed in the base of minimum volume value.
EFFECT: optimized well operation.
FIELD: oil and gas extractive industry.
SUBSTANCE: foam-forming compound for shutting wells contains hydrocarbon liquid, mixture of surfactants, one of components thereof is water solution of lignosulphonate reagent of 25% concentration, herbal filling agent and 20% water solution of calcium chloride, as lignosulphonate agent reagent it contains powder-like technical lignosulphonate, and as other component of surfactant mixture - hexamethylentetramine, and as herbal filling agent - peat or grass flour with following ratio of components in percents of mass: hydrocarbon liquid 12-14, said water solution of technical powder-like lignosulphonate 17-21, hexamethylentetramine 0.17-0.63, peat or grass flour 3-6, said calcium chloride solution - the rest, while relation of mass portions between said water solution of technical powder-like lignosulphonate and hexamethylentetramine is 1: 0.01-0.03 respectively, as grass flour it contains pulverized herbal waste of grain bread production or similar substance.
EFFECT: higher efficiency.
2 cl, 18 ex, 1 dwg
FIELD: oil and gas extractive industry.
SUBSTANCE: compound includes water and inhibiting salt, as inhibiting salt contains processed electrolyte - side product during production of magnesium via electrolysis from carnallite, and additionally as reducer of filtering and thickener - carbooximethylcellulose polymer, and as colmatation agent - magnesium oxide with following relation of components in percents of mass: processed electrolyte - side product of magnesium production via electrolysis from carnallite 10.0-15.0, carbooximethylcellulose 2.5-3.0; magnesium oxide 1.0-2.0, water 80.0-86.5.
EFFECT: higher efficiency.
FIELD: oil and gas producing industry, in particular composition for killing of well.
SUBSTANCE: claimed polysaccharide gel contains sweet or mineralized water, polysaccharide gelling agent, boron cross-linking agent, diethanolamine, quaternary ammonium compounds, and mixture of non-ionic and anionic surfactant (complex surfactant). Mixture of water soluble oxyethilated alkylphenols and their sulphoethoxylates in form of sodium salts or salts with triethanolamine is used as complex surfactant in amount of 0.1-0.5 kg on 1000 l of water being the gel base. Polysaccharide gel is obtained by dissolution and hydration of polysaccharide gelling agent in sweet or mineralized water (preferably monovalent ion solution) followed by treatment of obtained polysaccharide solution with aqueous solution including boron cross-linking agent, diethanolamine, quaternary ammonium compounds, and complex surfactant.
EFFECT: well killing composition of improved quality.
2 cl, 6 ex, 1 tbl
FIELD: oil extractive industry.
SUBSTANCE: method includes mounting compressor pump in such a way, that input aperture of tail piece was positioned below bed sole. Prior to that water cone in face-adjacent zone is destroyed by draining water through tail piece, connected to lower suck-in valve of compressor pump cylinder, and along behind-pipe space through side suck-in valve of compressor pump cylinder. In case of increase of hydrocarbon contained in drained liquid beginning of water cone destruction is assumed. Draining is continued until destruction of emulsion in water cone, formed in non-homogenous porous environment of bed at limits of hydrocarbon-water and water-hydrocarbon, separation of water and hydrocarbon streams and bringing current water-hydrocarbon contact to initial position. Then during extraction water is drained through tail piece, and hydrocarbon - along behind-pipe space.
EFFECT: higher yield.
3 cl, 1 dwg
FIELD: oil and gas industry.
SUBSTANCE: method includes preparation of technological liquid - water solution of sylvinite ore mixture with chlorine calcium by solving a mixture of components in hot fresh technical water, drained from oil and water preparation plants or bed water. During solution of sylvinite ore mixture with chlorine calcium in bed water the latter is drained from the well at temperature 60-90°C. Technological liquid is produced with solution density 1.23-1.37 t/m3. Then prepared technological liquid is fed into well shaft a bit lower, oppositely to zone and above ceiling of productive bed with forming of hydraulic column above the latter. Then well shaft to the mouth is filled with water. Value of technological liquid hydraulic column of high density on basis of said mixture, fed into well shaft above ceiling of productive column of technological liquid is taken in amount, necessary and enough from well stopping conditions.
EFFECT: higher efficiency.
6 cl, 1 ex
FIELD: oil and gas production.
SUBSTANCE: water-based composition that can be used for killing of well during pullout of hole and well remedial work as well as for temporary abandonment of well contains, wt %: carboxymethylcellulose3.5-4.5, sodium hydroxide1.5-2.0, copper sulfate 0.3-0.4, and methanol 4.0-16.0.
EFFECT: improved rheological properties of composition and increased lifetime of formed gels.
FIELD: oil and gas industry.
SUBSTANCE: method includes serial pumping into well of buffer, blocking and pressing liquid, blocking liquid contains hydrocarbon base, acyclic acid, caustic soda and mineral filler with following relation of components in percents of mass: hydrocarbon base 41-72, acyclic acid 6.1-14.4, caustic soda 4.9-13.0, mineral filler the rest. Hydrocarbon base of blocking liquid is oil or oil processing products. As mineral filler blocking liquid has calcium carbonate with diameter of particles no less than 2 micrometers.
EFFECT: higher efficiency, simplified maintenance, simplified construction.
3 cl, 1 ex
FIELD: oil industry.
SUBSTANCE: at least one acoustic dynamic is mounted immediately on product pipe in oil well and acoustic characteristic of flowing environment flow is determined in product pipe. It is sent into surface controller, using product pipe. Using surface controller flowing substance flowing mode is determined, on basis of which working parameters of oil well are adjusted. Working parameters of oil well can be adjusted to detect Taylor mode of flow. For adjustment of working parameters throttle is used and/or controlled valve of oil well, controlling amount of gas, forces into product pipe. For determining mode of flow of flowing environment artificial neuron net can be used. It is possible is provide energy for acoustic sensor through product pipe. It is possible to determine additional physical characteristics of flowing substance, for example pressure and temperature.
EFFECT: higher efficiency.
3 cl, 22 dwg
FIELD: mining industry.
SUBSTANCE: system has first induction throttle, second induction throttle and controlled switch. Second induction throttle is positioned near second branch of pipeline structure. Controlled switch has two outputs. First switch output is electrically connected to pipeline structure on the side of induction throttles connection, where first and second branches of pipeline structure intersect. Second output of switch is electrically connected to pipeline structure on other side of at least one induction throttle. Pipeline structure can be positioned inside oil well, and can have casing string and operation tubing column. Also described is method for extracting oil products from oil well using said system.
EFFECT: higher efficiency.
4 cl, 10 dwg