Method for optimising extraction from well with artificial lifting
FIELD: oil and gas industry.
SUBSTANCE: method for optimising extraction from a well is proposed, in which an artificial lifting system in a well shaft is controlled, and multiple parameters of extraction on surface and in the shaft well are monitored. A well model with calculated data parameters is built. Then, measured data on working face and surface of the well is compared to the model data and reliability of the measured data is checked. After that, difference between measured data and modelled data is diagnosed, and operation of an artificial lifting mechanism is adjusted as per the above diagnostics results.
EFFECT: ensuring enlargement of analysis volume of a well and components of an extraction system for effective extraction optimisation as a whole.
The level of technology
The technical field to which the invention relates.
The present invention relates to oil and gas wells with artificial lift and, in particular, to such wells using electric submersible pumps.
Description of the prior art,
In many wells with artificial lift has the potential to significantly improve and increase production. There are many mechanisms of artificial lift fluid from the reservoir, including electric submersible pumps and gas lift system. When using these systems artificial lift a lot of mechanical and system components can limit usage optimization system. For example, the components of the artificial lift can be locked, deleted, to have the correct size, be operated at sub-optimal speeds, or otherwise represent constraints to improve the optimal use of the entire system.
Attempts were made to detect certain specific problems. However, it turned out that a comprehensive analysis of the well and/or system components is difficult after the system is placed in the bottom of a well and put into action.
In General, the present invention before the is method and system optimization of the production in the well. The system of artificial lift, such as electric submersible pumps, operated in the wellbore. During the many parameters of production are tracked on the surface. At the same time, many well parameters monitored in the wellbore. The parameters of production and the well parameters are estimated according to the optimization model in order to determine whether production is optimized. If not, the mechanism of artificial lift is adjusted based on the evaluation of various parameters of production and well parameters.
Brief description of drawings
The following describes specific embodiments of with reference to the accompanying drawings, in which similar reference numbers indicate similar elements, and:
Figure 1 is a schematic illustration of a methodology to optimize production in a borehole according to a variant implementation of the present invention;
Figure 2 is a vertical section of an electrical submersible pumps used in the well in order to raise the fluid to the surface, according to a variant implementation of the present invention;
Figure 3 is a sequence diagram of the operations of method selection and optimization of production in the well according to a variant implementation of the present invention;
Figure 4 is a schematic representation of VA is Ianto implementation of the control system, which can be used to automatically implement the methodology or methodology, illustrated in figure 3;
Figure 5 is an illustration of the parameters used in option selection;
6 is an illustration of a system that can be used to retrieve data for processing according to the methodology of optimization of the well illustrated in figure 3;
7 is an illustration of one possible implementation of the system and approach that can be used for modelling of the borehole;
Fig is the precedence diagram illustrating the approach to the validation of the received data;
Fig.9 illustrates an example graphical user interface that can be used in order to simplify the validation data;
Figure 10 is a graphical representation of the characteristics of the flow, which can be used in process validation;
11 is a graphical representation of the calculations above the pump used in the process of validation;
Fig is a graphical representation of the calculations in the pump used in the process of validation;
Fig is a graphical representation of the calculations under the pump used in the process of validation;
Fig - this is Hema sequence of operations, to illustrate the approach to the validation of the received data;
Fig is the precedence diagram illustrating the methodology of diagnostics of potential restrictions on usage optimization system; and
Fig is a diagram representing the set of corrective actions that can be applied in order to optimize the production in the well.
Detailed description of the invention
In the following description describes a multitude of details in order to provide an understanding of the present invention. However, specialists in the art should understand that the present invention may be practiced without these details and that there are many possible variations or modifications of the described embodiments.
The present invention in General relates to a system and method for optimizing the use of artificial lift, such as electric submersible pumps. The process enables the system of artificial lift to be analyzed and diagnosed in order to provide input data for the optimization of the extraction wells. However, the optimization criteria may relate to different categories depending on the diagnostic results. For example, optimization may relate to optimize the purpose of reducing the pressure in the reservoir, optimize start-up time, optimizing the design and/or size or optimize efficiency. Optimization of this well may consider one or more of the above criteria, as well as other potential criteria.
The General approach to the optimization described in the diagram the sequence of operations figure 1. Originally identified wells with artificial lift with the performance, as shown in step 20. After identification of wells with poor performance is identified, the cause of inadequate performance, as shown in step 22. Identification of the causes of inadequate performance allows the implementation of corrective procedures, as illustrated in step 24. In the end, the cause of the problem is identified and action is taken or adjustment in order to optimize performance. Depending on your environment and specific equipment, the reasons and the action selected, i.e. corrective actions may vary, as described in more details below.
Although this General approach can be applied to multiple wells with artificial lift, the present description is primarily related to the optimization of wells in which the electrical submersible pump is used to artificially looking is the substance of the fluid from the well. Figure 2 illustrates an implementation option system 26 electric submersible pumps. In this embodiment, the system 26 of the pump is placed in the barrel 28 wells drilled or otherwise formed in the geological formation 30. System 26 electric submersible pumps suspended below the wellhead 32 placed, for example, on the surface 33 of the ground. System 26 of the pump is suspended by system 34 deployment, such as a production tubing column, the column in the bays or other system deployment. In the illustrated embodiment, system 34 deployment contains tubing column 36 through which the fluid medium well, served in the mouth 32 of the well.
As illustrated, the shaft 28 of the wellbore lined with casing 38 of the wellbore has a perforation intervals 40 through which fluid flows between the formation 30 and the shaft 28 of the well. For example, fluid hydrocarbon-based can flow from formation 30 through the perforations 40 in the barrel 28 wells near the system 26 electric submersible pumps. After logging into the barrel 28 of the well system 26 pumps can issue the fluid up through the tubing of the column 36 in the mouth 32 of the well and the desired collection point.
Although the system 26 electrical pogrujen the x pumps can contain many components, the example in figure 2 is illustrated as having a submersible pump 42, the suction hole 44 and motor 46, which feeds the submersible pump 32. The engine 46 receives electrical energy through a power cable 48 and protected from malicious fluid to the borehole through the protector 50 of the engine. In addition, the system 26 pumps may contain other components, including a connector 52 for connecting components with system 34 deployment. Another component illustrated is a block 54 of the sensors used to detect multiple parameters of the wellbore. However, it should be noted that many systems of sensors deployed in the system 26 electric submersible pumps, casing 38 or other areas wellhead can be used to retrieve the data, as described in more detail below. Furthermore, multiple sensors can be used on the surface 33 in order to obtain the required data, which helps in the optimization process well.
One example of a methodology for the optimization of production in the well can be described with reference to the illustrated sequence of operations of the method according to figure 3. Originally variants wells are selected on the basis of indications of insufficient performance (step 56). In the selected well or SLE is jinah data obtained for to measure the performance of artificial lift, for example, system 26 electric submersible pumps (step 58). (In this example, the measurement data is synchronized and implemented in real time in order to significantly improve the accuracy and completeness "of the painting operation used in the analysis of potential problems that contribute to lack of performance). Then the well is modeled based on the known parameters associated with well and electric submersible pumps. Simulated well matched with the measured data, as illustrated in step 60. Then checked the accuracy of the data (step 62). After validation can be performed system diagnostics artificial lift, does well in fact, lack of performance, and if so, the conditions that contribute to the lack of performance (step 64). Diagnostics system enables the implementation of changes, such as the provision of new settings in relation to the operation of the system 26 electric submersible pumps (step 66).
Some or all of the methodology, indicated with reference to figure 3, through automated system 68 processing, as schematically illustrated in figure 4. The system 68 of treatment can be computing analyst who, having a Central processing unit (CPU) 70. The CPU 70 is operatively connected with the storage device 72, and also the device 74 and input device 76 conclusion. The device 74 input can contain multiple devices, such as keyboard, mouse, block, speech recognition, touch screen, other input devices, or a combination of the above devices. The device 76 output may contain a visual device or output, such as a monitor having a graphical user interface. Additionally, the processing may be performed on a single device or multiple devices in the well, remotely from a borehole or using some of the devices in the well, and other devices located remotely.
System 68 processing can be used, for example, to enter the parameters relating to choices, to accept data from the phase of the receive data, to simulate the borehole and to check the validity of the associated data. System diagnostics artificial lift, and the implementation of the new settings can also be managed automatically by the processing system, such as system 68. However, it should be taken into account that the structure and implementation of the system 68 of the handle may vary significantly between applications, and the desired interaction between the analyst is 68 and optimization may vary depending on design requirements and constraints the structure and constraints of applications.
As briefly described with reference to figure 3, the original options are selected wells. For example, in the oil fields with a large number of systems, electrical submersible pumps, it is important that the likely options for optimizing hoteltravel from wells that are currently running under optimum conditions and at optimum speeds. In one approach option can be used to filter the wells according to the priority of increasing oil production to help achieve maximum success in minimum time. Recognition of suboptimal wells with rise relative to other wells in the field is not a simple task and requires an assessment of various data and information.
The ability to identify the possible ways of optimization often depends on obtaining accurate data relevant to the wells. For example, it may be useful to monitor the trend data in order to determine the consistency and, consequently, the accuracy of the original data when determining probable variants of optimization.
In addition, it is important to determine which parameters are the key parameters that will help in the selection of possible options. In relation to systems, electrical submersible pumps, examples of potential key parameters is illustrated in the diagram Fig. Other key parameters are valid, but the illustrated examples are watering 78, index 80 well performance, availability actuator 82 with adjustable rate and wellhead pressure 84. In this case, higher levels of watering indicate less potential to increase oil production. However, a higher index indicates greater potential to increase oil production at small business changes. The availability of a variable speed drive in the well, allows changing speed, which may significantly affect the current flow. In addition, if high wellhead pressure, reducing this pressure often causes a significant increase in oil production.
Selecting wells to obtain information in order to measure the performance of artificial lift. Typical data obtained through a variety of sensors, which may contain, for example, distributed temperature sensors and pressure gauges. In addition, it may be advantageous to use a sensor system providing streaming data in real-time. Tracked trends in the data with a common time and date to facilitate selection of points of interest from the trend lines, thereby providing a more accurate "snapshots" of working with the vazhiny for to help with the analysis.
Figure 6 illustrates a variant of the implementation of the sensor system used to facilitate the optimization of the electrical submersible pump. Various sensors can be connected to the system 68 of the processing that can compare the data and display meaningful information specialist and/or to use the data to perform the analysis of the well. Although many parameters can be used in the analysis of this well, Fig.6 illustrates examples of surface measurements 86 and dimensions 88 in the wellbore, which can be obtained in real time and provided to the system 68 processing for analysis. Examples of surface sensors and/or monitored parameters include sensors 90 temperature and pressure in the tubing columns, the sensors 92 pressure within a casing, the sensors 94 frequency for detecting the frequency of an electrical signal, the sensor 96 data multiphase flows, sensors 98 common threads and gauges 100 power. Examples of sensors and/or controlled parameters of the wellbore includes sensors 102 pressure in the suction hole of the pump, the pressure sensors 104 in the injection hole of the pump, the sensors 105 temperature in the suction hole, distributed sensors 106 temperature sensors 107 feeding speed of the pump, sensor and 108 temperature of the engine and the sensors 109 vibration. However, many other sensors designed to detect additional parameters can be added. For example, some of the options for implementation may be designed to use sensors 110 viscosity for detecting the viscosity of the fluid, the sensor 111 density and the sensors 112 to determine the onset temperature of the beginning of the boil. Additionally, it may be not necessary to use all of the illustrated sensors. For example, in some embodiments, the implementation of the methodology described in this document can be accessed with a unique subset of the illustrated sensors, for example sensors 90, 92, 94, 96, 102, 104 and 106.
In addition to receiving data, consider the well is modeled. However, modeling of a well varies depending on the environment in which the drilled wellbore, the reservoir parameters and the type and components of the system of artificial lift. Proper modeling of the borehole allows contrasting the measured data retrieved from the monitored parameters, the optimization model in order to simplify data analysis and, ultimately, the optimization of the well. As illustrated in Fig.7, the program 114 modeling wells can be used in the system 68 processing in order to compare the ISM is certified or input data for display to the specialist on the device 76 output or for further processing in the course of verification and diagnostic data. As an example, the program 114 simulation to compare the measured data based on the monitored parameters with the corresponding calculated values of the model and to provide a graphical comparison of, for example, the graph 116 (coefficient gas/oil depending on pressure), 118 (ratio of reservoir volume of oil depending on the pressure) and 120 (viscosity depending on the pressure), is illustrated in Fig.7. However, specific data collected and the desired simulation can vary significantly depending on the specific application. The example program that is implemented in software, which can be used in the system 68 processing to simulate wells is a software product ALXP (the increase in production systems with artificial lift)offered by Schlumberger Technology Corporation of Sugar Land, Texas, USA. ALXP can be used to simulate wells that have deployed electric submersible pumps, and also to help in the validation and analysis of data.
As briefly described above, collecting real-time data from multiple sensors and data assimilation for comparison with a predetermined model is an important basis for the optimization of this well. However, the effectiveness of corrective actions is increased by what redstem checking the reliability of the actual data collected, as well as the use of these data for modeling well. Described in this document, the example system electric submersible pumps proper optimization may depend on data PVT (pressure, volume and temperature), the gradient of the fluid above the pump 42, the pressure drop in the pump 42 and flow compared to the flow. Therefore, one approach to the validation of this type of system is to check the validity of each of these parameters. As illustrated in Fig, the process of validation may include checking the validity of PVT-data (step 122), the validation of the gradient of the fluid above the pump (step 124), the validation of pressure drop in the pump (step 126) and the validation of expenditure in comparison with the flow (step 128).
The accuracy of PVT-data can be retrieved in a variety of ways depending on the specific analyzed PVT-data. For example, the actual ratio of gas/oil (GOR), the ratio of reservoir volume of oil (Bo) and data on viscosity of oil can often be obtained from the operator of the well. Other data can also be defined or Torremirona. For example, a fixed correlation can be used to determine the calculated value temperature pressure initial boiling point and coefficient of reservoir volume of oil. Corr is the transmission of Beggs can be used to calculate the viscosity of the oil. Predefined or calculated values used to make the model well, with which the measured PVT data can be compared for validation. As illustrated in Fig.9, the system 68 processing and device 76 output can be used to display, for example, graphic correlation, comparing the calculated or simulated values with the measured values in order to highlight any differences.
Accurate data flow may also be important in the validation set thread-related parameters. Calculating the ratio of inflow performance (IPR) can be carried out according to the multitude of ways. For example, can be used the values of inflow from the operator of the well; direct production index (PI) can be calculated from the data speeds of the control flow and the hydrodynamic pressure of the well; direct IPR can be determined from the given PI and static reservoir pressure or calculated from the velocity control flow and control pressure; or schedule Vogel, or composite IPR can be extracted from the data speeds of the control flow, the hydrodynamic pressure of the well and coefficient of Vogel. The results can be graphically displayed on the device 76 conclusion. One example t is whom graphical display provided on figure 10, in which is illustrated a direct IPR, in which the flow rate of fluid korrelirovana with hydrodynamic pressure of the well.
Validation of the gradient of the fluid above the pump uses calculations "on pump". Use the following equation: the pressure in the injection hole of the pump = wellhead pressure (WHP) + Delta P pump and compressor columns (density) + Delta P pump and compressor columns (friction). Calculation "above the pump draws the gradient of the fluid from the measured wellhead pressure to the pressure in the injection hole of the pump. If the pressure in the discharge outlet of the pump is known, this value can be used to accurately determine or compare the gradient in order to ensure the ability to verify the accuracy of the information on the density of the fluid (95% pressure drop in the tubing string). If the pressure in the injection hole is unknown, requires accurate measurement of the water content, GOR and total flow rate. Validation of the gradient of the fluid, as graphically illustrated by figure 11, is important because subsequent steps in the process of validation is based on the exact determination of the specific gravity of the pumped fluid. Referring in General to 11, the gradient tech is whose environment above the pump illustrated in box 130.
In order to compare the gradient of the fluid from the wellhead pressure with the pressure in the discharge outlet of the pump, the properties of the fluid, affecting the density of the fluid can be adjusted. Good basic assumption is that at least 95 percent of the pressure losses in the tubing string consists of a pressure loss due to the density of the fluid, and the pressure losses due to friction are relatively small. Therefore, it is possible to accurately determine the gradient of the fluid, in order to compare the measured pressure in the injection hole by adjusting the data, which affect the density of the fluid. This can be accomplished by adjusting, for example, values of water content and/or General GOR. A match occurs when the calculated pressure in the injection hole of the pump corresponds to the measured pressure in the injection hole of the pump.
Next can be calculated "at the pump". Use the following equation: the pressure in the suction hole of the pump = pressure in the injection hole of the pump - pressure drop in the pump. The pressure drop in the pump (pound per square inch) is equal to the value multiple of the head (feet) specific gravity/2,31. Calculate the pump determine the pressure drop in the pump and draw the calculated pressure what s in the suction hole of the pump from a certain pressure in the injection hole of the pump. The density of the fluid (specific gravity), the reliability of which is checked, allows you to use the measured data to help verify the accuracy of information about the flow velocity. Information about the flow velocity can then be cross-checked with calculations of inflow. The gradient pump is graphically illustrated in Fig through field 132.
As described above, the calculated pump rate is a function of the pressure drop in the pump and the density of the fluid. The accuracy of the density of the fluid previously verified by comparing the gradient above the pump, thereby allowing the comparison of the pressure drop in the pump suction pressure, using the stream as a parameter calibration. It should be noted that this assumes that the characteristic of the pump is not deteriorated due to viscosity or wear. Additional verification flow can be executed later by cross-validation with the flow.
Additionally, calculations "under the pump" can also be performed to further verify the reliability of the measured parameters. Use the following equation: hydrodynamic pressure wells (FBHP) = pressure in the suction hole + loss of pressure in the casing. Use e the e one equation: hydrodynamic pressure wells = formation pressure - (index stream/production). The accuracy of the flow rate can be checked at operating conditions, using both values of pressure losses in the tubing string, wellhead pressure, and so on) and the values of inflow (IPR-data).
The gradient of the consumption is finally determined by calculation under the pump, which generates the gradient of the fluid from the suction opening of the pump to the hydrodynamic pressure wells in the perforation holes in the casing. Calculation "to the bottom" determines the hydrodynamic pressure of the well from the data on the inflow and draws the gradient to the depth of the suction hole of the pump. Schedule under the pump and the graph to the bottom should match the total pressure in the suction hole and the hydrodynamic pressure of the well. The gradient under the pump graphically illustrated in Fig through field 134.
In General, the pump performs the same calculation was performed on the pump. The flow turns downward, and inward (to the bottom) is obtained from reservoir pressure to the suction hole of the pump. If the measured flow rate, reservoir pressure, and the index of production is correct, the computed schedules must be consistent with the measured data.
On Fig illustrated is an example methodology validation of the measured data associated with the system is an electric submersible pumps. The methodology includes many of the above steps or approaches. The system first checks the validity of the data flow, as indicated by step 136. Validation of data flow can contain a mapping gradients above the pump on the basis of measured and calculated values (step 138). Validation of data flow may additionally include performing calculations in the pump (step 140) and scheduling gradients under the pump (step 142). Next tested the reliability of the data flow, as illustrated by step 144. Verification entails the calculation of hydrodynamic pressure wells and comparing the calculated values with the measured value (step 146). Validation of the data flow may also contain graphs gradients to the bottom for comparison data (step 148). Next, it turns out, the working point of the pump, as illustrated by stage 150. The working point is obtained for the comparison of measured and calculated values (step 152).
As described above, the calculated values are used to construct a model of optimal well performance, which can be contrasted with the measured data extracted from the monitored parameters. This process of validation measured the data reveals any discrepancies between the model values and the measured data. Differences that arise effectively direct diagnosis of potential problems that limit the performance of the well. Diagnostics can be performed in the system 68 processing in order to beg a quick and accurate assessment of potential problems. When using electrical submersible pumps lifting the fluid, the diagnosis can be performed, for example, according to the precedence diagram method, illustrated in Fig.
As illustrated, initially gather data relating to the set associated with the extraction of parameters, for example, the PVT-data, the depth of the well, the well productivity, the geometry of the borehole, data pump, data on reservoir tank and other data, as illustrated in step 154. The next step in the diagnostic process is the comparison of measured PVT-values calculated from the PVT values (step 156). The program checks all discrepancies (step 158) between the measured data and calculated values. If a discrepancy exists, an indication of this discrepancy can be displayed on the device 76 output for viewing by a specialist, as shown in step 160. The discrepancy can be resolved by checking the obtained correlations and/or checks associated with the extraction of values provided by the operator of the well.
Next, the wire is aetsa gradient above the pump (step 162), as explained above. The calculated gradient is compared with measured data in order to determine whether the gradient of the measured data (step 164). If the gradient does not match the measured data (step 166), different values, such as water content, depth wellhead pressure, etc. are checked, and the program returns to step 162 to again check the gradient above the pump. On the other hand, if the gradient is above the pump corresponds to the measured data, the computation is done in the pump (step 168), as described above.
When you run the calculation in the pump performs a determination as to whether the pressure drop in the pump to be associated with the measured pressure in the suction hole, as illustrated in step 170. If the pressure drop is the same, checked the reliability of the suppression performance of the flow (step 172) and is performed to determine properly the flow corresponds to the flow rate (step 174). If Yes (step 176), there is a coincidence between calculated values and measured values. If not (step 178), it should be made more diagnostics to determine the source of the discrepancies and potential problems that prevent optimization of the potential wells.
Returning to step 170, if the differential pressure does not coincide with the measured pressure is receiving in the suction hole, the various parameters should be checked, as illustrated in step 180. For example, flow rate, frequency, information about the pump, the pump flow depending on the flow and other parameters should be checked and identified their reliability in order to determine whether errors occur. If the adjustments of the parameters (step 182), then the calculation above the pump must be started again. Otherwise, should be made an additional diagnosis (stage 184) in order to determine the source of the discrepancies and potential problems that prevent optimization of the potential wells.
Comparing the calculated values with the measured values and the differences between these values can provide an indication of the specific issues that caused suboptimal prey. The meaning of relationships and divergence data, however, may vary depending on the type of artificial lift, system components, artificial lift and environmental factors. Additionally, differences can sometimes be resolved by simply operating adjustments such as adjustment of the fitting or valve, to provide greater or lesser flow or adjusting the output frequency of the variable speed drive. Other discrepancies may indicate worn the components of the coefficients, defective components, locked components or other required adjustments. For example, in the above system, which uses a system of electric submersible pumps in order to extract the fluid wells, it is assumed that if the suction inlet of the pump is blocked, the following conditions are true:
- unreachable coincidence between the measured and calculated pressure in the suction hole when performing calculations in the pump (pressure measured in the suction hole is higher than the calculated pressure in the suction hole);
- the gradient to the bottom can be associated with pressure in the suction hole; and
- the actual pressure in the suction hole of the pump is low, and the measured data is higher, provided that the point at which the measured data of the pressure sensor in the suction hole is located above the lock.
As another example, recirculation of the fluid in the wellbore, for example, due to leakage in the tubing string may be assumed if the following conditions are true:
- calculated inflows can be compared with the pressure in the suction hole with the help of this source flow rate measured at the surface;
- calculations on the pump correspond to the use of this and the initial flow rate, measured on the surface; and
- calculate the characteristics of the pump shows that the flow rate must be much higher to get a match at the working point. However, this higher flow rate generates a higher pressure in the injection hole above the pump.
Once diagnosis is complete, is the appropriate corrective action to optimize well performance. As illustrated in Fig, corrective action (step 186) may contain the implementation of the new settings and/or other corrective action, as illustrated by steps 188, 190, 192, 194 and 196 of action. Depending on the design goals of the entire system, at least some corrective actions should be automated through system programming 68 processing to perform such corrective action based on the results of the simulation, test and troubleshoot well. For example, if the optimization entails the adjustment of the flow rate, the corresponding signals can be provided by the system 68 processing to, for example, to adjust the fitting (step 188) or to adjust the frequency of the variable speed drive (step 190). Other corrective actions, such as cleaning the suction from the Erste (step 192) or the leak in the tubing string (step 194) may entail significant action to repair or replace components, which require human intervention.
Although only a few embodiments of the present invention described above, the experts in this field of technology should take into account that many modifications will be allowed without derogation essentially from the methods of the invention. Therefore, these modifications are intended to be included within the scope of this invention defined by the claims.
1. A method of optimizing production in a well, comprising stages, which are: control system of artificial lift in the wellbore; monitor many parameters of the production on the surface; monitor many parameters of the wells in the well bore; build the model well with the calculated data parameters; evaluate the measured data obtained from a variety of parameters measured downhole and on the surface with simulated data parameters; check the reliability of the measured data; after validation diagnose discrepancies between measured data and simulated data and regulate the mechanism of the artificial lifting-based diagnostics.
2. A method of optimizing production, when the system of electric submersible pumps containing a pump, powered by a submersible motor is used in the image quality is as artificial lift for extraction of the fluid, containing phases in which: collect related with production data; comparing the measured data of the pressure, volume and temperature (PVT) with the calculated PVT data, calculated according to the required model; validate the measured PVT data; after validation diagnose discrepancies between the measured PVT data and the calculated PVT data; optimize production based on a diagnosis of the measured PVT data and the calculated PVT data.
3. The method according to claim 2, in which the optimization contains the stage at which change the flow rate by adjusting the valve.
4. The method according to claim 2, in which the check contains the stage at which compare the gradient above the pump.
5. The method according to claim 2, in which the check contains the stage at which compare the gradient pump.
6. The method according to claim 2, in which the check contains the stage at which compare the gradient under the pump.
7. The method according to claim 2, in which the check contains the stage at which compare data flow data flow.
FIELD: oil and gas industry.
SUBSTANCE: method includes stress inducing in formation around well shaft in order to generate in it some special feature related to induced stress. Measurements presenting well shaft geometry are performed using assembly of drilling string bottom rotated in well shaft, which geometry presents induced stresses in formation. Creation of well shaft image based on its geometry measurements. Evaluation of azimuth variation of induced voltage in formation by well depth. Change of parameter of drilling mode for assembly of drilling string bottom using evaluation of azimuth variation of induced voltage in formation by well depth.
EFFECT: using data obtained in real-time mode, checking stress model for certain region, so that the path may be corrected constantly for achievement of optimum ratio with measured characteristics of stress for this region.
21 cl, 12 dwg
FIELD: oil and gas industry.
SUBSTANCE: by-pass system of oil well pumping unit for dual pumping of a well having at least two formations consists of Y-shaped unit installed at pipe string and pumping unit and string of bypass pipes with landing nipple for setting of removable blind plug are connected to the bottom part of this unit. Fishneck is located at setting of removable blind plug in the nipple in Y-shaped unit over the string of bypass pipes while the latter is fixed to the pumping unit by means of clams. Landing nipple is manufacture so that geophysical plug can be set in it instead of removable blind plug. In the well beneath by-pass system with pumping unit there are at least two packers of mechanical, hydromechanical or hydraulic action. Each packer is installed over respective well formation and at formation level between them there is at least one chamber with union or flow adjuster or stationary mandrel or pilot-controlled valve with hydraulic, electrical or mechanical actuation and ability to adjust flow passage with two positions of open and closed. Over the top packer there is pipe string disconnector at which adapter in disengaged status is installed. At the lower end of pipe string there is a blind plug or nipple-hopper. Besides geophysical plug can be set into landing nipple in by-pass of pumping unit instead of removable blind plug and nipple-hopper is fixed at the string of bypass pipes from the bottom. Upwards the latter the string of bypass pipes and pumping unit are interconnected by supporting structure. Telescopic sleeve is installed under the landing nipple at string of bypass pipes. Removable blind plug has sliding skirt in the upper part for pressure balancing and a tip in the lower part for wire or rope fixing. Bypassing method involves trip in hole of the tool at logging cable; the tool is installed at the logging cable with geophysical plug. Two hammers with frictional insert or inner surface with jagged notches are installed at the logging cable. The bottom hammer is installed 10-20 m higher then the tool. The top hammer is installed at bigger or equal distance from location point of geophysical plug in Y-shaped unit before the lower boundary of the surveyed formation. Geophysical plug is made with slide-off bushing in order to balance pressure.
EFFECT: improving operational reliability of downhole equipment during surveys of wells in production string downstream pumping unit due to accident-free removal of removable blind plug and geophysical plug in surveying process.
5 cl, 9 dwg
FIELD: oil and gas industry.
SUBSTANCE: tool contains sectional case with installed collar locators (CL), gamma-ray loggers (GRL), pressure sensors (P), temperature sensors (T), humidimeter (W), thermoconductive flowmeter (TCF) and resistivity metre (RM) from top downward; in pressurised portion of the case there are GRL, LM and P sensors at that sensitive membrane of P sensor is connected to environment by hydrochannel, while T sensors, W, TCF and RM are located in pressurised cavities of non-pressurised portion of the case. At that T and W sensors are shifted in relation to longitudinal axis of the device at equal distances and are installed in the case at place with two pairs of mutually perpendicular reach-through windows having different width and equipped with cross bulkheads, at that the device is equipped with flowmeter module consisting of centraliser, liner, body and metre run with RPM sensor and rotation direction sensor installed along axis of the body. In the upper part of the device there is also force sensing device, and between the device and flowmeter module there is an additional docking device with clamper and double-hinged mutually perpendicular electroconductive unit with offset of rotation axes in relation to longitudinal axis of the device; the device is equipped with additional three dimensional module or humidimeter (W) or thermal moisture tester (T-W) or viscometer (V).
EFFECT: improving operational performance of the device and expansion of its application area.
6 cl, 3 dwg
FIELD: oil and gas industry.
SUBSTANCE: method consists in emission of sounding pulses by means of a generator solenoid located inside tested pipes, the axis of which coincides with axis of the tested pipes, and measurement of EMF induced in receiving coils by means of an electromagnetic field decrease process. Magnetic flux is measured, which is caused by sounding pulses of the generator solenoid, by means of sensors located along the instrument perimetre at distance r from the probe axis, opposite the end face of the generator solenoid, in N sectors on radial direction.
EFFECT: enlarging application area and improving quality of pipe flaw detection.
FIELD: oil and gas industry.
SUBSTANCE: method involves arrangement of an fibre-optic cable in a production well; determination of well shaft temperature; build-up of a temperature vs. well depth graph; indication on the graph of a temperature rise minimum by 10 degrees, which is the closest one to the well head; determination of depth of well liquid level as corresponding to depth of the indicated temperature rise.
EFFECT: determination of liquid level in a well with high temperature for extraction of high-viscosity oil.
FIELD: measuring equipment.
SUBSTANCE: for determining the characteristics of pore volume and thermal conductivity of matrix of samples of porous materials, the sample of porous material is alternately saturated with at least two fluids with different known thermal conductivity. As at least one saturating fluid a mixture of fluids from at least two fluids with different known thermal conductivity is used. After each saturation of the sample the thermal conductivity of the saturated sample of the porous material is measured, and the characteristics of pore volume and thermal conductivity of the matrix of the sample of porous material is determined taking into account the results of thermal conductivity measurements.
EFFECT: increased accuracy and stability of determining the characteristics of the pore volume and the thermal conductivity of the test samples.
14 cl, 2 dwg
FIELD: oil and gas industry.
SUBSTANCE: standard electric logging of a well is carried out in low-temperature rocks, the area of possible bedding of gas hydrates and hydrate formation is identified in them. In the identified area of low-temperature rocks, on the basis of data of standard electric logging, zones are registered, in which measured values of the apparent electric resistance of low-temperature rocks are equal to at least 15 Ohm.m. Coolant is pumped in the investigated rock interval, afterwards thermometry is realised using highly sensitive thermometers, providing for error of temperature measurements of not more than 0.01°C, and zones are sought for, rock temperature in which, relative to the lowest registered temperature in the identified zone is at least by 0.2-0.5°C lower than the temperature of rocks adjacent to the borders of the detected zones. At the same time the latter zones are considered as zones containing gas hydrates. The area of possible bedding and hydrate formation is the area of rock bedding characterised by availability of thermobaric conditions for gas hydrates existence in rocks.
EFFECT: its higher efficiency by detection of gas hydrate rocks bedded in low-temperature rocks below a foot of permafrost rocks.
3 cl, 1 dwg
FIELD: oil and gas industry.
SUBSTANCE: method includes delivery of a shank with a set of packers and unions, downhole geophysical multi-purpose device to the hole end at a logging cable. Pumping into the well of a fluid containing thermal- and neutron-contrasting agents and periodical measurements. Contrasting fluid is pumped by several portions with volumes not less than interior volume of the horizontal borehole by means of subsequent switching into operation of different boreholes intervals covered by packers, by means of opening and closure control of outlet connections. Oil is used as a contrasting fluid instead of water. Movement of the contrasting fluid through the borehole is monitored by gamma-ray modules, resistivity meter or thermoconductive flowmeter.
EFFECT: improving accuracy for determination of operating intervals and sources of flooding under conditions of horizontal wells operation.
5 cl, 6 dwg
FIELD: oil and gas industry.
SUBSTANCE: method includes acquisition of log data on depth and time for a well drilling by means of a well string; log data on depth and time including data related to factors of torsional and axial loads and data related to hydraulic factor; and determination of a drill string neutral point at the moment of drilling based on factors of torsional and axial loads and hydraulic factor.
EFFECT: determination of a drill string neutral point during well drilling.
20 cl, 4 dwg
FIELD: oil and gas industry.
SUBSTANCE: method includes simulating of formation and recording of data on borehole processes by a geophysical instrument run-in into the tubing string at a logging cable and self-contained instruments installed at the lower end of the tubing string. At that simulation of formation is made by breaking a breakable drain valve made of a brittle material of hemisphere shape and installed with a convex part downwards in the lower part of the tubing string; for this purpose a drill stem is fixed under the geophysical instrument and the geophysical instrument is run-in with the stem into the interval with speed sufficient to break the breakable drain valve. At that upper part of the tubing sting above the breakable drain valve is not filled with water and a packer is installed in tubular annulus at the level of the tubing string lower part.
EFFECT: increase of information content and reliability for borehole investigations; reduction of labour intensity, time consumption and equipment costs; possibility to use in wells with any producibility of the investigated formation.
FIELD: oil and gas industry.
SUBSTANCE: well is equipped bottom upwards with a tubing string ended with a packer, submerged pump, switch, two outer and inner annulus of the tubing string which are located concentrically, tubes with holes at the outer tubing string. The well is splitted over the productive stratum. The stratal product is delivered by the submerged pump in a cyclic mode "delivery-stop" from the productive stratum through the tubing string, the switch, tubular annulus between inner and outer tubing string, tubes and holes of tubes into tubular annulus between the production string and outer tubing string. Pressure is created and maintained in the upper pert of the well; it should not be less than oil degassing pressure and more than permissible pressure to the production string. Separation of the stratal product into oil and water is arranged in the upper part of the well. Completeness of separation is controlled by the duration of a half of the operation cycle of the submerged pump till stoppage and by the distance between switch and the tube with a hole. Oil is delivered to oil line. Water is supplied through the switch to inner tubing string and through the pipeline to an injection well by borehole-to-borehole water pumping and/or through tubular annulus between the production string and outer tubing string and tubing string with a packer to the stratum over the packer by borehole water pumping.
EFFECT: improvement of oil and water separation degree, increase in injection efficiency of separated water during borehole and borehole-to-borehole pumping of water.
1 ex, 1 dwg
FIELD: oil and gas industry.
SUBSTANCE: device contains a spherical body with at least one segment containing at least one section of throttle joints and one limiting. Stream is fed to the segment from the butt end, through side channels. Each input unit can be covered by a roller gate of the plug with thread which is input through the chamber body.
EFFECT: increasing oil recovery of the formation.
12 cl, 1 dwg
FIELD: oil and gas industry.
SUBSTANCE: method involves lowering to the well of a pipe string with a cable, control devices in the form of electric valves, pressure and temperature measuring sensors and with one or several packers isolating the borehole space. Sensors are used, the information from which is supplied to a measuring unit installed on the well head. Signals for opening and closing of control devices are supplied via the cable from the wellhead control unit. The product is lifted to the surface by means of a pump via inter-tube space. The well is built with a horizontal section passing in the formation with different permeability zones. Packers are installed in the horizontal section of the well, thus separating the formation zones with different permeability. The inter-tube space is isolated with a plug, above which there arranged one above another are upper and lower control devices arranged in a vertical shaft and equipped with measuring sensors. Zones with equal or similar permeability are interconnected with each other by being grouped in two flows interconnected with the borehore space and the input of the upper control device or the inter-tube space and the input of the lower control device. Outputs of control devices are interconnected with the pump inlet, and the value of opening of control devices is derived with frequency separation via one cable, via which parameters are picked up from measuring sensors, as per the readings of which the value of opening of each of the control devices is determined. Each control device is made in the form of an electric motor with a reduction gear, which are arranged in the housing, the rotating shaft of which is connected through a screw-nut connection to a pusher and a valve having the possibility of tight interaction with a seat, below which there arranged is a shell with an inlet in the form of channels, in which a compensating chamber with elastic walls is arranged, which is filled with lubricating liquid and interconnected with inner space of the pusher and sealed space located above the pusher.
EFFECT: enlarging manufacturing capabilities in wells with zones of different permeability, and reducing costs.
2 cl, 4 dwg
FIELD: oil and gas industry.
SUBSTANCE: method lies in accumulation of liquid and gas in a well, cyclic carryover of accumulated liquid from the liner to tubing string and throwing of liquid column by gas. According to the invention associated gas is separated from liquid-gas mixture and directed to the upper part of gas-lift unit to gas burning unit. Air under high pressure is fed to the same unit in order to provide conditions for gas-air mix burning ensuring high-speed burning process accompanied by sharp increase of temperature and pressure. In result it provides opening of return valve in the lower part of tubing string and throwing of liquid column by gas being a combustion product. Thereafter cycle of gas separation from liquid-gas mixture and its burning in gas-air mix is repeated as far as liquid and gas enter through the service valve from annular space to the lower part of submerged gas-lift unit at receipt of a signal from the earth control station.
EFFECT: increase in efficiency, reduction of power consumption, control of production process and reduction of costs for well operation.
FIELD: oil and gas industry.
SUBSTANCE: method consists in movement of a housing of a continuous circulation tool to an adapter having a channel passing through it and intended for connection in a pipe string in the well and selective movement of drilling fluid between the housing and a side hole in the adapter; in addition, the continuous circulation tool includes a shutoff device, and actuation of a shutoff mechanism to introduce a shutoff element of the shutoff device through the side hole in the adapter for insulation of drilling fluid flow through at least one section of the channel. A system for carrying out well operations with continuous circulation of drilling fluid, which contains a continuous circulation tool interconnected with a tubular column of the well, which contains an adapter and is intended for selective shutoff of the drilling fluid flow to tubular column of the well, a pipe manipulating device near the adapter, which contains the following: a pipe wrench, pipe wrenches, a pipe wrench, a retaining wrench, a pipe wrench and a spinning wrench and a device for mechanised suspension and unscrewing of pipes.
EFFECT: maximum drilling speed.
34 cl, 27 dwg
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
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: 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.