Method for determination of parameters for well bottomhole and bottomhole area
FIELD: oil and gas industry.
SUBSTANCE: invention is related to the area of wells completion and testing in oil industry and intended for calculation of parameters for the well bottomhole and bottomhole area. The method where in process of string movement in the well pressure is measured by two sensors, at that one sensor is installed over the packer while the second one is installed below the packer. According to results of pressure measurement fluid density is determined and then flowing bottomhole pressure is determined on the basis of fluid density, gravity constant, preset rate of drilling string motion, cross-sectional area of the drilling string, formation pressure, and productivity index of the well.
EFFECT: potential determination of parameters for the well bottomhole and bottomhole area during round-trip operations with further calculation of liquid influx/reflux at the bottomhole and calculation of skin factor, permeability or thickness of the reservoir.
13 cl, 5 dwg
The invention relates to the completion and testing of wells in the oil and gas industry and is designed to calculate the parameters of the face and the bottom zone of the well, such as, for example, skin factor, permeability, power collector, the bottomhole pressure and the outflow or inflow in this area.
In the prior art there are known various methods for determining the parameters of the face and the bottom zone. Thus, in U.S. patent No. 4799157 described method of test wells for evaluation of permeability and skin factor of two reservoirs, one reservoir. The method consists in performing two consecutive hydrodynamic investigations of wells (well testing) by creating a depression on the bottom with a permutation of the logging sonde and the subsequent interpretation of the data on the flow rates and pressures.
In U.S. patent No. 5337821 the method of calculating the maximum hydroconductivity collector, as well as the method and measuring device for measuring flow rates, the full potential of the flow rate at the flowing well and whether violations of the permeability zone of the formation from production. Measurements shall be conducted after the descent of the tool into the borehole to a predetermined depth and isolating intervals using inflatable rubber packers.
In U.S. patent No. 7675287 describes how to assess the skin factor podzemnih the collector inside the wellbore by lowering the measuring device at a certain depth and dimension properties of nuclear magnetic resonance formation at multiple depths.
In the patent application U.S. No. 2011/0087471 proposed to establish a functional relationship between reservoir properties, characteristics of the bottomhole zone/completions, as well as measured characteristics of the well. Confirmed values of reservoir properties such as permeability, characteristics of the bottomhole zone/completion, such as the skin factor is determined by establishing a functional dependency.
A common shortcoming of these patents and patent applications is that they all require special equipment or special operations in the borehole to determine the properties of the face and the bottom zone. The difference of the present invention is that to define the properties of the face and the bottom zone is usually available when the investigation or operation of the wells. In other words, to define the parameters is not required of non-standard equipment or additional operations.
Technical result achieved during the implementation of the claimed invention, is to provide the possibility of determining the timing of slaughter and the bottom zone, such as downhole pressure during tripping with subsequent calculation of the inflow/outflow of the liquid at the bottom and calculate the skin factor and permeability or power collector. realizacija the proposed method can be implemented using a conventional pressure gauges, which are widely used in the oil industry, without descent special tools into the well.
In accordance with the proposed method in the process of moving the tubing in the borehole carry out measurements of pressure and temperature, the results of which estimate the parameters of the face and the bottom zone.
The parameters of the face and the bottom zone can be dynamic bottom hole pressure, the dynamics of the absorption of the liquid collector, the dynamics of inflow of fluid from the reservoir, the total amount of acquisitions or inflow, skin factor, permeability or rate of a header.
Measurement of pressure and temperature can be performed via at least one pressure sensor and the temperature set in any place the pipe string.
Measurement of pressure and temperature can be carried out by means of two pressure sensors and temperature, one of which is mounted above the packer and the second below the packer.
Measurement of pressure and temperature can be performed by means of a pressure sensor and a temperature that is installed in the string of pipe so that it is as close as possible to the collector at the end of the descent of the column to the desired depth.
Measurement of pressure and temperature can be performed via at least one gauge and one sensor is temperature, installed in any location in the pipe string.
Measurement of pressure and temperature can be performed via at least one gauge and one temperature sensor installed in the string of pipe so that it is as close as possible to the collector at the end of the descent of the column to the desired depth.
Column pipe may be provided with any additional instruments such as samplers.
In accordance with one variant of the invention the measurement of pressure and temperature is carried out in the process of lowering the pipe string into the well.
Measurement of pressure and temperature can be carried out in the process of lowering the pipe string into the borehole before the work on the perforation interval.
In accordance with another variant of realization of the invention the measurement of pressure and temperature is carried out in the process of lifting the pipe string from the well.
Measurement of pressure and temperature can be carried out in the process of lifting the pipe string from the well after the perforation interval.
In accordance with another variant of the invention the measurement of pressure and temperature is carried out in the process of lowering the pipe string into the well and in the process lifting the pipe string from the well.
The invention is illustrated by drawings, where Fig.1 shows the system for the implementation of tripping and measurements; in Fig.2 - the process of displacement, shown in a simplified geometric form; Fig.3 - geometry used in the example implementation of the calculations of Fig.4 - position/level of the liquid in the annulus and the position of the drill pipe with the layout of the test reservoir (reservoir) along the borehole with respect to time, Fig.5 - certain hydrodynamic downhole pressure and total volume of acquisitions.
The present invention is as follows.
As shown in Fig.1, column 1 pipe or column 1 pipes with additional tools lowered into the borehole 2 from the surface 3 to perform certain operations. Sensor 4 for measuring pressure and temperature is set in the column pipe 1. The system can be installed additional sensor 5 or more additional sensors for measuring pressure and temperature. Column 1 of pipe is lowered into the well 2 until it reaches the position 6 at a certain point in front or close to the underground reservoir 7. Readings of pressure and temperature recorded during the whole period of the descent of the column 1 pipe from the surface 3 to the point of slaughter 6. After the operation of the descent, all operations scheduled in the hole, and lifting tubes, temperature sensors and pressure are retrieved on the surface of the measurements, which were taken during tripping, and measurements obtained during schedule execution.
In the case of using two pressure sensors and one temperature sensor can be installed above the packer, and the other below the packer. The layout with the installation of two sensors allows to determine the density p on the basis of the pressure difference between the readings of the two gauges. Using the equation of hydrostatic pressure, we obtain:
where g is the constant of gravity, lg- the distance between the gauges and θg- the average angle of inclination of this part well. Note that the last formula holds for slow processes, in which the pressure loss by friction play a less significant role than the hydrostatic pressure drop. Temperature measurement can be used to establish the relationship between the properties of the liquid on the surface and measuring point data in underground conditions.
Consider the volume balance during the downward movement of the tubing in the well. For simplicity we neglect the compressibility of the fluid is in and will make the assumption, the fluid level in the annulus rises vertically, while the movement of the drill pipe or column tubing layout for testing formations (reservoirs) is carried out on an inclined (see Fig.2).
Moving a column of drill pipe layout for testing formations (reservoirs) displaces a certain volume of liquid ΔVDSTduring the period of time Δt. At the same time, the volume of fluid in the annulus is increased by ΔVanand the volume ΔVris absorbed by the collector. Therefore, in this case we have
Data volumes can be easier expressed in the following form
where ΔzDST- measured the depth of advancement of the drill pipe during the time Δt (8 in Fig.2), Δzan- lifting height of the liquid column in the annulus during the time Δt (9 in Fig.2), Aan- the cross-sectional area available for flow in the annulus, A
Substituting the last expression in equation (1) and dividing by Δt, we obtain
Member in the left-hand side of equation (2) expresses the rate of descent of the drill pipe layout for testing formations (reservoirs)
The value is their velocity ν DSTis accepted as a given value. Usually this rate is of the order of several centimeters per second. Now consider the first term in the right-hand side of equation (2). The increase in liquid level in the annulus proportionally increasing hydrodynamic downhole pressure, which for slow processes in almost a vertical well is basically the hydrostatic component.
where Δpwfindicates a change in downhole pressure during the time Δt.
Note that more complex geometric features and the interval velocities can be taken into account in the last equation. The second term in the right-hand side of the equation can be expressed, for example, of the stationary ratio of the flow of fluid in the production well (the ratio of hydrostatic pressure spouting with flow rate).
Here k is the permeability, µ is the viscosity, re- the radius of the pressure, s is the skin factor, pe- reservoir pressure, defined on the radius of the pressure.
Replacing three of the last equality in equation (2) when Δt→0, we get a simple ordinary differential equation of the first order.
where PI is the productivity index of the well.
Equation (3) can be written in explicit discretized form.
Equation (4) is easily solved numerically to calculate the hydrodynamic hydrostatic pressure pwfthat, in turn, allows us to calculate the volumetric flow rate of liquid absorption by the collector of Qloss(t). The skin factor s is determined by selecting values that meet the specified parameters, conditions, and requirements test parameters (see below). It should be noted that in this problem the value of the permeability k can be unknown (defined) value. In this case, it could be found at a given skin factor and the capacity of the reservoir h. the other hand, the power collector h could also be unknown (defined) value. In this case, it can be found for a given skin factor and permeability k.
The reliability of the results predicted by the model can be verified by calculating the following test parameters: the position of the drill pipe layout for testing formations (reservoirs)
Mark the liquid level in the annulus
and the pressure of the lower pressure gauge
You must note that for simplicity, the values of zDST(t) and zan(t) measured along the borehole, since the borehole bottom.
As a specific example of implementation of the invention consider the configuration of the wells shown in Fig.3, which is characterized by the following parameters: the length of the inclined section l1=2127.04 m (13 in Fig.3), the length of the vertical section of the l2=500 (14 in Fig.3) m and the angle θ=20° (15 in Fig.3). The length of the interval punching is h=10 m, the reservoir pressure is pe=200 bar (the radius of the pressure re=500 m), and the permeability is k=50 MD. In this example, the value of the skin factor s is an unknown quantity. The density of the fluid in the flow is ρ=1000 kg/m3and viscosity µ=1. Suppose that during the descent the column for the first time in contact with the liquid at the point of inflection, in which the bottomhole pressure equal to the hydrostatic pressure ρgh1=pe. From this equation we see that the height of the column of liquid the spine in the wellbore before the operation was equal to h 1=2000 m (16 in Fig.3).
Trip operation in this case consists of two periods of descent of the drill string in the borehole and a short period of lifting from wells between these periods, until the end of the movement of the column. The average speed was adjusted so that the value'zdst calculated using equation (5), is zero when the column stops moving (the lower the unit reaches the final measured depth of the wellbore, the curve 17 in Fig.4). As a result of this correction, we obtain the absolute value of the νDST=0.03735 m/s (see Fig.4).
After the selected value of the νDSTto set parameters need to make sure that the value max(zan)=l1+l2at the end of the trip operation (curve 18 in Fig.4) indicated that the level of liquid in the annulus rose to the level corresponding to the indication of the correct hydrostatic pressure on the manometer. It automatically equalizes the calculated bottomhole pressure design pressure on the manometer, which is obtained using equation (7). Good agreement is obtained for the value of the skin factor s=60 (see Fig.5, where curve 19 represents the dynamic downhole pressure curve 20 indicates the pressure on the pressure gauge, obtained using equation (7) and curve 21 indicates the amounts of the RNA outflow in the collector). The diagram also shows the total losses ∫Qlossdt.
The proposed method can also be applied to cases with more complex geometries.
1. The method for determining the parameters of the face and the bottom zone of the well, in accordance with which
in the process of moving the tubing in the borehole perform pressure measurement with two sensors, one of which is mounted above the packer and the second below the packer,
- the pressure measurements to determine the density of the fluid and determine the dynamic bottom hole pressure from the equation
where ρwfdynamic bottom hole pressure, ρ is the density of fluid, g is the constant gravity, νDST(t) - set speed of movement of the drill pipe string, ADST- the cross-sectional area of the drill pipe, ρe- reservoir pressure, PI is the productivity index of the well defined by the formula
where k is the permeability, h - power manifold, µ is the viscosity, re- the radius of the pressure, rwis the radius of the borehole, s is the skin factor.
2. The method according to p. 2, under which determine the volumetric flow rate of liquid absorption by the collector according to the formula
where Qloss- volumetric flow rate of liquid absorption by the collector, ρwfdynamic bottom hole pressure, ρe- reservoir pressure, k is the permeability, h - power manifold, µ is the viscosity, re- the radius of the pressure, rwis the radius of the borehole, s is the skin factor.
3. The method according to claim 2, whereby the total amount of acquisitions is determined by integrating the volumetric flow rate of liquid absorption by the collector over time.
4. The method according to p. 1, according to which if one value from the group consisting of skin factor, permeability and the capacity of the collector is unknown, the value of the unknown quantity picked by substitution in the equation for determining the dynamic downhole pressure and further variation of this value to ensure the satisfaction of specified parameters and requirements for all test parameters.
5. The method according to p. 4, in accordance with which the test parameters are:
the position of the drill pipe layout for testing collectors
where zDST(t) is the position of the drill pipe string, zDST(0) - the position of the drill pipe string at the initial moment of time, νDST(t) - set speed of movement of the drill pipe during the movement,
- mark the liquid level in the annulus
where zan(t) - the level of fluid in the annular por the space zan(0) - the liquid level in the annulus at the initial moment of time, ρwfdynamic bottom hole pressure, ρe- reservoir pressure, ρ is the density of fluid, g is the constant of gravity, compared with the level of liquid in the annulus defined by the readings of the pressure sensor, and
- estimated pressure at the point where a lower pressure sensor
where ρgc(t) is the estimated pressure at the point where a lower pressure sensor, ρe- reservoir pressure, ρ is the density of fluid, g is the constant of gravity, zDST(t) is the position of the drill pipe layout for testing collectors, θ is the angle of inclination of the borehole, measured relative to the vertical, which is compared with the pressure measured bottom pressure sensor.
6. The method according to p. 1, according to which the pressure sensors are pressure gauges.
7. The method according to p. 1, according to which in the process of moving the tubing in the well additionally carry out temperature measurements.
8. The method according to p. 1, according to which a column of pipes fitted with additional tools.
9. The method according to p. 1, in accordance with which the pressure measurement is carried out in the process of lowering the pipe string into the well.
10. The method according to p. 9, under the which the pressure measurement is carried out until the work on the perforation interval.
11. The method according to p. 1, in accordance with which the pressure measurement is carried out in the process of lifting the pipe string from the well.
12. The method according to p. 11, in accordance with which the measurement of pressure and temperature is carried out after the work on the perforation interval.
13. The method according to p. 1, in accordance with which the pressure measurement is carried out in the process of lowering the pipe string into the well and in the process lifting the pipe string from the well.
FIELD: oil-and-gas industry.
SUBSTANCE: evaluation of fluid inflow fraction from every productive zone of multi-zone productive well comprises determination of pressure at wellhead. Integrated indicator curve (IPR1) is obtained to describe the relationship between pressure and fluid yield from first productive zone and integrated indicator curve (IPR2) is obtained to describe the relationship between pressure and fluid yield from second productive zone. Value for integrated indicator curve at the point of mixing (IPRm) is obtained with the help of IPR1 and IPR2. Initial fluid inflow fraction from first productive zone at mixing points and initial fluid inflow fraction from second productive zone are defined. First total curve of outflow (TPR1) is obtained describing the relationship between fluid pressure and yield, fluid flowing from mixing point to wellhead. First portion of fluid inflow from first productive zone (Q11) and first portion of fluid inflow from second productive zone (Q21) are defined at mixing point with the help of IPRm and TPR1. Machine-readable carrier accessible for processor comprise program including instructions for above listed jobs.
EFFECT: more efficient evaluation of the portion of influx from productive seam.
20 cl, 5 dwg
FIELD: measurement equipment.
SUBSTANCE: system (100) of sensors for measurement of a technological parameter of a fluid medium in a well location, comprising a resonator (110) of a parameter, which is located in a well (106), having resonance frequency that varies depending on the technological parameter of the fluid medium and which in response generates a resonant acoustic signal on the resonance frequency that indicates the technological parameter. Besides, the system comprises an acoustic sensor (118), arranged in the location near above the surface, spaced from the parameter resonator, a measurement circuit (102), connected with the acoustic sensor, and an acoustic source connected with a pipe in the location near above the surface and spaced from the parameter resonator placed in the well. At the same time the acoustic sensor is made as capable of receiving the resonant acoustic signal, transmitted from the parameter resonator, the measurement circuit is arranged as capable of formation of an output signal of the technological parameter, corresponding to the technological parameter of the fluid medium, in response to the received resonant acoustic signal, and the acoustic source is arranged as capable of transmission of the acoustic signal into the well.
EFFECT: provision of measurement of well fluid medium properties in real-time mode both in process of drilling and in process of well operation.
20 cl, 6 dwg
FIELD: oil and gas industry.
SUBSTANCE: the method is realized in two stages. At the first stage to the lower horizontal producer a flow string is run in to the beginning of a slotted filter. A heat insulated filter is set in the upper horizontal injector above the slotted filter. In the upper horizontal injector temperature tests are made in the interval from the well head up to the packer. Steam is injected to the lower horizontal producer and temperature tests are made simultaneously in the upper horizontal injector. Upon completion of steam injection to the lower well the final temperature test is made in the upper well. At the second stage fresh water is injected to the upper horizontal injector and a heat insulated flow string is run in with a thermal packer and shank. The packer is set before the slotted filter and control temperature test is made in tubular annulus in the interval from the well head up to the packer. Steam is injected to the upper horizontal injector though the heat insulated flow string, through the packer and shank to the beginning of the slotted filter. At that, periodically, upon commencement of injection, temperature tests are made in tubular annulus in the interval from the well head up to the packer. Upon completion of steam injection the final temperature test is performed in the upper horizontal injector. When required, tests in the lower producer and operational procedures for the wells are interchanged.
EFFECT: improving authenticity of the obtained results during identification of intervals with cross flows behind the casing for wells operated in deposits of viscous and superviscous oil.
SUBSTANCE: proposed device comprises housing to accommodate the set of pressure and temperature gages, moisture metre and flow metre, electronics unit connected by logging cable, on one side, with surface control station and. On opposite side, with said gages, coupling unit with cable joint head and centring skid. Instrumentation module is secured at said housing by leverage, said module including inclination metre and extra gages, at least, moisture metre and flow metre connected with electronics unit. This module can reciprocate along the gravity vector between casing pipe and housing. It is located at casing pipe profile lower part by centring skid and coupling unit. It is equipped with housing turn drive and instrumentation module to turn them from gravity vector set by inclination metre via electronic unit.
EFFECT: registration borehole fluid interface boundaries and flow rate of every separate phase in conditionally horizontal wells.
4 cl, 3 dwg
FIELD: oil and gas industry.
SUBSTANCE: bubble-point pressure determination method includes measurement of bottomhole pressure at different oil production rates and registration of bottomhole pressure change curves upon returning the well to production in linear and nonlinear oil influx modes above or below bubble point pressure. At that wellhead pressure change curves and dynamic level changes in annular space are recorded additionally. By measurement results average density is calculated at each moment of time for the mixture column at annular space and the curve of average density changes in time at annular space is plotted. The free gas release is fixed when a gas separator releases it to the annular space. The value of bubble point pressure is determined by comparison of the mixture density change curve with pressure changes at pump suction at a certain period of time.
EFFECT: improvement of accuracy measurement of bubble point pressure.
1 tbl, 1 ex, 3 dwg
FIELD: oil and gas industry.
SUBSTANCE: invention is related to a method of well production optimisation. Intervals are selected in a deviated offshoot and drill-stem testing and borehole treatment is deployed. Then each interval is isolated in order to perform the required testing. The obtained testing data are evaluated in order to define respective recovery measures, which are implemented later by means of the drill-stem testing and borehole treatment.
EFFECT: provision of testing and treatment for the plenty of intervals in a horizontal hole during one running to the borehole.
11 cl, 6 dwg
FIELD: oil and gas industry.
SUBSTANCE: method lies in measurement of the maximum dynamic head depth for the known well-killing fluid with homogeneous density when bringing the well on to stable production after killing according to the following formula Pbthp=ρkf.·g·(Hperf-HDHmax), where ρkf - density of the well-killing fluid, kg/m3; g - acceleration of free fall, m/s2; Hperf - height of the upper perforated openings, m; HDHmax - maximum dynamic head depth in the well when bringing the well on to stable production after killing, m.
EFFECT: reducing downtime during well surveys, improving accuracy and reliability while determining the bottomhole pressure and simplifying of the bottomhole pressure measurement when bringing the well on to stable production after killing.
FIELD: oil and gas industry.
SUBSTANCE: monitoring method of inter-well parameters, at which by means of a laser radiation source there formed with the specified duration and frequency is a light pulse entering a fibre-optic cable where dissipation radiation is evolved through the cable length. Dissipation radiation entering a processing unit is converted to an electric signal and amplified. Then, a useful signal supplied to the input of the second controller is separated from it, where frequency of displacement of the useful signal relative to generation frequency of the laser radiation source is determined, and then, as per its value there calculated is a current value of pressure change parameter; the obtained data is compared to the those specified in the first controller, at deviation of which an oil recovery process is automatically controlled in compliance with the change of inflow, which is determined by continuous measurement of the well pressure change; electric motor shaft rotation frequency is controlled; when pressure change parameter value is lower than the specified value, the electric motor shaft rotation frequency is increased, and when the pressure change parameter value is higher than the specified value, then the electric motor shaft rotation frequency is decreased.
EFFECT: optimisation, automation and enhanced efficiency of an oil recovery process.
16 cl, 3 dwg
FIELD: oil and gas industry.
SUBSTANCE: well production rate is changed and temperature is measured during certain time period for fluid flowing to the well from each layer; temperature variation value ΔTP is measured for initial stage and steady-state value A of temperature-time logarithmic derivative is calculated for each layer. Specific yield value q for each layer is determined against the specified mathematical expression. Yield Q for each layer of the well is determined and influx profile is defined as totality of yields Q for all layers.
EFFECT: improving accuracy of well parameters determination.
FIELD: oil and gas industry.
SUBSTANCE: method includes double recording of temperature distribution along well bore by thermal logging with two identical thermometers located at certain distance from each other along the well bore and further comparison of received temperature logs. Comparison of received temperature logs is made by their correction processing and by results of such comparison summary is made about geophysical inhomogenuities in well formations or formation influx.
EFFECT: eliminating necessity in double measurement of distributed temperature along wells axis during pumping and selection of fluid for the purpose of survey of well state.
3 cl, 3 dwg
FIELD: well boring, particularly for measuring pressure in well during drilling thereof.
SUBSTANCE: device has body with central flushing orifice and grooves. Arranged in the grooves are electrical circuits and positive pressure transducers isolated by pressure-resistant shell. The first pressure transducer is connected with central flushing orifice in tube, another one - with annular tube space. The device is provided with power source and two differential amplifiers with outputs connected to summing unit inputs. Supply diagonal units are linked correspondingly with power source inputs. The first units of measuring diagonals of the first and the second pressure transducers are connected correspondingly with inverting and non-inverting inputs of the first differential amplifier. The second units of measuring diagonals of the first and the second pressure transducers are linked correspondingly to inverting and non-inverting inputs of the second differential amplifier. The first and the second pressure transducers may be arranged in the body at 0°-45° and 153°-180° angles to vertical device axis correspondingly or may be inversely arranged. The body may be formed of titanic alloy.
EFFECT: increased measuring reliability.
4 cl, 2 dwg
FIELD: survey of boreholes or wells, particularly in borehole geophysical instrument requiring additional thermal stabilization.
SUBSTANCE: mounting with members to be thermostated is arranged inside heat absorbing device. Heat absorbing device is made as a set of heat absorbers, each of which is made as hollow heat-conductive cylinder filled with heat absorbing material. Heat insulator is formed as cylindrical heat-protective shell with outer and inner ring-shaped ribs and adapted for receiving heat absorbers. Heat-conductive mounting have heat absorbing plugs connected to ends thereof. Each heat-absorbing plug is made as hollow heat-conductive cylinder filled with heat absorbing material. Surfaces of heat-protective case, heat-protective cylindrical shell, heat absorbers and heat absorbing plugs facing thermostating members are covered with heat absorbing coating. Surfaces thereof facing borehole are covered with heat-reflecting coating.
EFFECT: increased duration of working thermostating cycle and simplified structure of thermostat.
6 cl, 2 dwg
FIELD: survey of boreholes or wells, particularly for tracing pressure distribution along well bore and for diagnosing various situations in well bore.
SUBSTANCE: method involves temporarily blocking part or full fluid flow by quick-acting valve gate along with continuously recording pressure in point spaced a small distance from the valve gate in upstream direction; determining friction losses with the use of Darcy-Weisbach equation; plotting diagram depicting pressure as a function of distance on the base of above time diagram and on the base of acoustic speed in real fluid with the use of the following relation: ΔL=0.5aΔt, which correlates time Δt with distance ΔL. To estimate acoustic speed in fluid one may use correlations which determine relation between hydraulic impact value, fluid pressure, fluid velocity and acoustic speed in the fluid and which are known from Joukowski formula. Acoustic speed also may be estimated on the base of time determination between pressure change peaks depicted on time diagram and caused by equipment, flow sectional area and other parts located along well bore, discharge line and pipeline in predetermined points. Acoustic speed may be determined on the base of changes in time diagrams in at least two different points along pipeline and by comparison of above time diagrams. Combined well temperature and pressure diagram may also be obtained, wherein above temperature distribution along well bore depth is measured with the use of optical fiber. Above method may be used to determine and localize influx points in well bore, discharge line and pipeline or to determine and localize losses from well. Method may also be used to determine and localize collapse of discharge lines or presence of deposits, namely hydrates, solid hydrocarbons, pyrobitumen or sand. Above method may be used to determine effective diameters of well bore, discharge line or pipeline in different sections thereof, or to determine which gas lift valves are in working state and to localize and determine working characteristic values of pipeline equipment utilized for oil and/or gas production.
EFFECT: increased efficiency of well survey.
12 cl, 11 dwg, 2 ex
FIELD: survey of boreholes or wells, particularly devices for differential pressure measurement equipment during balanced or unbalanced well boring.
SUBSTANCE: method involves determining excessive pressure inside drilling string and in annular space is static mode with the use of excessive pressure sensors, wherein the sensors communicate with flushing orifice and hole annuity through pressure supply channels; taking greater or lesser excessive pressure as actual pressure; determining difference between greater and lesser pressure values and estimating above difference in dynamic regime in pressure supply channel having lesser static pressure if greater excessive pressure is chosen as the actual pressure value or in pressure supply channel having greater static pressure value if lesser excessive pressure is chosen as the actual pressure.
EFFECT: increased sensitivity of differential pressure sensor and measurement reliability.
FIELD: oil and gas industry, particularly to stimulate oil production.
SUBSTANCE: oil production is performed along with controlling of oil production parameters and speed of submersible pump electromotor rotation to maintain optimal values of oil production process parameters. Liquid level in well is chosen as the main oil production process parameter. Volume of liquid to be produced is chosen as parameter to be optimized. Control operation is carried out in several stages in automatic mode. At the first stage initial liquid level in well corresponding to calculated level, which provides maximal liquid inflow into well, is specified in pump motor control unit and pump operational mode is selected so that volume of liquid extracted from well is equal to volume of liquid flowing into well for the predetermined time period. Then liquid level corresponding to above situation is recorded and stored in memory. At the second stage predetermined initial liquid level in well is determined and then influx flow and extracted flow are equalized by pump mode of operation. Obtained value of extracted flow is compared with that at previous stage. If above value exceeds that obtained at previous stage predetermined liquid level is also increased and influx flow and extracted flow are equalized by pump mode of operation to increase predetermined liquid level in well in several stages up to corresponding extracted flow volume reduction. After that one backward step is executed, predetermined extracted liquid level corresponding to above step is taken as optimal level and above level is maintained during well operation. If extracted liquid volume decreases at the second stage predetermined liquid level change direction is performed in reverse order and then all above operations are repeated beginning from the second stage. Device for above method realization comprises electromotor to activate pumping jack, which is connected with submersible pump, extractable liquid volume sensors, well liquid pressure sensors connected to electromotor control unit. The control unit comprises serially connected memory means, frequency regulator and voltage changer. Control device is also provided with acoustic depth finding sensor, which determines liquid level in well and is installed at well head. The acoustic depth finding sensor is connected to one frequency regulator input. Extracted liquid volume sensor is connected to one input of memory means having the second input connected to command operator's console. Well liquid pressure sensor is connected to the second input of frequency regulator having output connected to electromotor through voltage changer.
EFFECT: increased oil output.
FIELD: mining, particularly oil and gas well testing.
SUBSTANCE: method involves lowering sample taking device suspended to wire or logging cable to take two or more deep fluid, gas or fluid and gas mixture samples in air-tight manner simultaneously, wherein the sample taking device comprises at least two sample taking chambers; communicating well space with sample taking chamber interiors by closing or opening the chambers with the use of hydraulic drive, which is actuated since sample taking sample taking device was lowered in well, wherein lowering, lifting operations, as well as operation for sample taking device retaining at sampling point are carried out along with measurement of pressure, temperature and sample taking device location depth. The sample taking chambers are opened or closed synchronously or alternatively. Hydraulic drive is operated by electromagnetic valve under control of electronic programmable controller, which controls valve opening and closing in accordance with preset time period or well pressure value. In the case of cable communication line usage the valve is controlled by control signal given from land-based unit. Sample taking device comprises electronic module, hydraulic drive assembly, one or several sample taking chambers, temperature and pressure sensors and programmable controller, which operates electromagnetic valve of hydraulic drive assembly, magnetic collar locator, natural radioactivity recording unit. All information fixed by sensors is digitized and stored in nonvolatile memory means. Sample taking device also has sensor system, which detects sample taking chamber valves opening and closing independently for each sample taking chamber. All measured parameters are digitized and stored in electronic module memory or is supplied to land surface in the case of cable communication line usage.
EFFECT: possibility to take sealed samples simultaneously in one well point or in several points located at different depths, possibility to perform continuous depth, temperature and pressure measurements inside the well in sampling point and along well bore, provision of independent control of each sample taking chamber.
9 cl, 3 dwg
FIELD: oil production well operation survey, particularly to control productive formation pressure along with information transmission via wireless communication channel.
SUBSTANCE: method involves lowering subsurface pressure gage connected to flow string and to well sucker-rod, wherein the subsurface pressure gage comprises pressure sensor and information transmission device, which transmits information via wireless communication channel; measuring pressure and transmitting information to day surface via wireless electromagnetic communication channel with the use of decompressor having variable base, wherein base length is defined by distance from productive formation roof to end of well sucker-rod filter and magnitude of temperature flow string length change adjusted for geometrical factor equal to 1 - 1.01. Device for above method realization comprises subsurface pressure gage provided with electromagnetic wave transmitter, which transmits electromagnetic waves generated by electric signal sent by decompressor electrically linked to well sucker-rod. The decompressor has variable base and is terminated in electrode located in lower variable base part. The electrode is electrically connected to casing pipe through centrator. Pressure sensor is arranged in electrode body and connected to electronic circuit. Device may be provided with additional pressure sensors connected with each other and forming pressure sensor string. Number of pressure sensors in the array is equal to number of production strings. Pressure sensors may be located opposite to corresponding productive formation center. Pressure sensors may be connected with each other through electric insulators adapted to receive multiple-strand electric cable passing inside the insulators. The pressure sensors may have electrodes electrically linked to casing pipe through centrator.
EFFECT: reduced time of pressure measurement and data transmission.
7 cl, 1 dwg
FIELD: testing the nature of borehole walls and formation testing particularly for obtaining fluid samples or testing fluids, in boreholes or wells.
SUBSTANCE: device comprises tubular body to be secured inside drilling string arranged in well bore. The tubular body is provided with one or several extensions created along body axis and forming expanded axial part. Probe is arranged in expanded axial body part zone having minimal cross-section. The probe may be moved between extended and retracted positions. In extended position probe may touch well wall to gather information from formation. To protect probe during drilling operation probe in brought into retracted position. Drive adapted to move the probe between extended and retracted positions is installed on the body.
EFFECT: increased accuracy of well and formation testing.
38 cl, 29 dwg
FIELD: survey of boreholes or wells, particularly measuring temperature or pressure in running wells.
SUBSTANCE: device comprises land-based assembly and submersed assembly including pressure transducer made as pressure unit linked to measuring resistor with output connected to land-based assembly inlet through diode and communication line. Land-based assembly includes power source, computing unit, digital indicator, the first analog-digital power source voltage converter, and the second analog-digital power source voltage converter. Land-based assembly input is linked to input of the first analog-digital converter having output linked to the first input of the computing unit. Land-based assembly input is also connected with the first output of power source having the second output linked with ground through resistor and with input of the second analog-digital converter. Output of the second analog-digital converter is connected to the second input of computing unit. The first output of computing unit is connected to digital indicator. The second output thereof is linked to power source input.
EFFECT: increased operational reliability.
FIELD: well survey, particularly geothermal well survey.
SUBSTANCE: temperature probe assembly comprises temperature sensors installed in upper or lower assembly part and uniformly distributed around a circle having radius r>R3/2, where R3 is probe assembly radius. Circle center coincides with probe assembly axis. Assembly also has safety lamp made as a pipe with orifices. Summary orifice area is not less than pipe cross-sectional area. The probe assembly may be provided with two centralizers arranged in upper and lower parts thereof. In some variants temperature sensor is arranged along assembly axis in upper or lower part thereof, probe assembly has safety lamp made as a pipe with orifices, wherein summary orifice area is not less than pipe cross-sectional area, and pressing device. The pressing device includes two springs arranged in upper and lower probe assembly parts. Temperature sensor is 1-2 mm under or over safety lamp end plane correspondingly. In other variants safety lamp has beveled end and is pressed to pipe string by short generator thereof. Probe assembly variants including temperature sensors and two centrators in upper and lower parts are also disclosed. The temperature sensors are arranged on each spring of upper centrator in upper part thereof or each spring of lower centrator in lower part thereof is provided with one temperature sensor spaced a distance from pipe string or production string axes. The distance is determined from equation. In just other variants probe assembly has centrators arranged in upper and lower parts thereof and temperature sensors carried by substrate formed of resilient material and arranged in lower probe assembly part between springs of lower centrator or in upper probe assembly part between upper centrator springs. Each spring is provided with limiting strip to restrict substrate and temperature sensor displacement with respect to probe assembly axis. Temperature sensors are located in upper or lower probe assembly parts in dependence of downhole instrument movement direction during well survey performance.
EFFECT: increased accuracy of continuous temperature measurement along generator defined by temperature sensor movement due to elimination of liquid mixing in front of temperature sensor.
12 cl, 7 dwg