Method and device for determination of optimal rate of fluid withdrawal on base of pressure determined in well at beginning of condensation

FIELD: mining.

SUBSTANCE: device contains receiving chamber for samples, pump, communicating with chamber, pressure measuring device, communicating with sample and optical analyser, optically connected with sample; device and analyser facilitate pressure drop in sample and determine pressure which provides extremum of light amount passing through sample.

EFFECT: preventing precipitation of hard substances and bubbling during sampling.

19 cl, 27 dwg

 

The technical field to which the invention relates.

The present invention relates to spectrometry in down hole conditions, in particular to a reliable device and method for determining the optimal rate of pumping based on the downhole conditions of pressure dew point or saturation pressure, which are either known or determined by measuring the optical spectra characterizing the absorption capacity of the sample of formation fluid in relation to electromagnetic radiation, in the process of reducing the pressure acting on the studied sample.

The level of technology

Hydrocarbon reservoir fluids present in the extraction of gas or oil well, are usually a mixture of oil, gas and water. Pressure, temperature and volume of reservoir fluids adjust the phase relationship of these components. Due to the high pressure fluid in the layers of underground rock in the oil under pressure greater than the saturation pressure, often penetrate gases. When lowering the pressure of the liquid-phase samples are allocated retained or dissolved gaseous compounds. Precision measurement of pressure, temperature and composition of the reservoir fluids from a particular well affect commercial viability of extracting extracted from the well fluids, the Results of such measurements also provide information, used to maximize the efficiency of the completion and development of the corresponding reservoir hydrocarbons.

There are certain methods of the study of well fluids in the well bore. In the patent US 6467544 (Brown and others) described receiving chamber for samples with piston installed in the camera can move and separating chamber to the cavity for samples with one side of the piston and the buffer cavity. In the patent US 5361839 (Griffith and others, 1993) revealed the transmitter for issuing a signal representing the characteristics found in the well of the sample fluid. In the patent US 5329811 (Schultz and others, 1994) disclosed a device and method of assessment data pressure and volume are related to the sample of well fluid in the well environment.

Other methods used for sampling well fluid to rise to the surface. In the patent US 4583595 (Czenichow and others, 1986) the mechanism of reciprocating drive for sampling well fluid. In the patent US 4721157 (Berzin, 1988) disclosed a movable valve sleeve for sampling well fluid into the chamber. In the patent US 4766955 (Petermann, 1988) disclosed a piston coupled with a control valve, for assaying downhole fluid, and in the patent US 4903765 (Zunkel, 1990) - a device for sampling well fluid with time delay. In the patent US 5009100 (Grber and others, 1991) revealed the sampler on the cable for assaying downhole fluid with a given well depth, in patent US 5240072 (Schultz and others, 1993) revealed responsive to annulus pressure device for screening multiple samples allows to take samples of well fluids in different periods of time and at various depth intervals, and in the patent US 5322120 (Be and others, 1994) disclosed hydraulic system with electric drive for sampling well fluid from deep wells.

The temperature in the wellbore at great depths often exceed 300°F. If the surface where the temperature is 70°F, remove a sample of hot formation fluid at a temperature of 300°F, the corresponding decrease in temperature will lead to the fact that the sample of formation fluid will tend to shrink in volume. If the volume of the sample remains constant, this reduction will cause a significant decrease in the pressure of the sample. The pressure drop can lead to changes in the parameters at which layer of fluid was in the well, resulting in a sample may be divided into phases: liquid and contained in the sample gas. The separation of the phases significantly modifies the characteristics of the formation fluid and reduces the possibility of assessing its actual properties.

To overcome this drawback have been developed various methods to maintain the pressure of the sample is listovogo fluid. In the patent US 5337822 (Massie and others, 1994) was proposed to create excessive pressure on a sample of formation fluid through the piston with the hydraulic actuator, powered by the energy of compressed gas under high pressure. Similarly, in patent US 5662166 (Shammai, 1997) suggests the use of compressed gas for "charging" samples of formation fluids. In patents US 5303775 and US 5377755 (Michaels and others, respectively 1994 and 1995) revealed positive displacement pump bilateral (double) steps designed to increase the pressure of the sample of formation fluid to a level above the saturation pressure, so that upon further cooling, the fluid pressure has fallen below the saturation point.

Capabilities of existing methods for sustaining the pressure of the sample at the level of the reservoir is limited by many factors. Prestressed springs and compression springs are not suitable for this, because to create the necessary compressive force it is necessary to use springs very large sizes. The mechanisms that create shifting efforts are non-configurable and do not allow sufficient ease to take several samples at different locations of the wellbore. The use of gas charges can lead to sudden depressurization seals and contamination of the sample. To ensure system operation podavlivaya gas the need for complex equipment, enabling the e tanks, valves and regulators, which are expensive, occupy the volume deficit in the cramped conditions of the wellbore, as well as maintenance and repair. Electric or hydraulic pumps should be controlled from the surface and have similar weaknesses.

If pumping the sample into the receiving tank pressure drops below the saturation pressure, or the pressure at which condensation, the formation of gas bubbles, the precipitation of solids and release hydrocarbons translates liquid-phase sample of crude oil, respectively, in two-phase and three-phase state, in which the sample consists of liquid and gas or liquid and solid substances. To analyze the characteristics of rocks in the borehole conditions seek to obtain samples in single-phase state, representing the wireline fluid in its natural state. Two-phase sample is undesirable because if the sample oil was divided into two phases, to return it to its original state single-phase flow can be difficult, if not impossible, and if it succeeds, it will take a long time (weeks), even after re-heating and/or stirring of the sample with the aim to translate it in single-phase state.

Because of the uncertainty of the recovery process samples the quality and consistency of the results of any laboratory analyses on the Nove ratio "pressure-volume-temperature (PVT), held in respect of petroleum recovered in-phase condition, perceived with a certain degree of doubt. There is therefore a need for a method of determining the pressure at which condensation of the sample of formation fluid, which would allow for the selection of the sample to select the optimum pumping speed, ensuring that when sampling the pressure will not fall below the pressure at which condensation or saturation pressure and eliminating the risk of getting damaged samples.

Summary of the invention

The present invention aims at eliminating the drawbacks of the prior art discussed above. The invention allows the sampling to prevent precipitation of solid substances and the formation of bubbles, thereby maintaining the sample in a single-phase condition. The present invention provides method and apparatus for determining the optimum speed pumping so that during sampling to avoid falling sample pressure below the pressure at which condensation. The invention provides for the use of downhole spectrometer to determine the pressure dew point to determine when sampling optimal speed pumping to avoid phase changes in the sample of formation fluid. A sample of hydrocarbon (gas)under reservoir pressure, C is clucalc adjustable in volume. In a regulated volume of lower pressure. First, the sample of formation fluid looks dark, as in the study of passes less light energy. But as the pressure decreases, and the sample pressure drops, it becomes more liquid, or less dense, it absorbs more light. However, when the dew point pressure of the sample begins to darken, passing through less light energy as it begins precipitation of asphaltenes. Thus, the dew point pressure is the pressure at which passes through the sample to a maximum of light energy. The dew point pressure is introduced into the equation to determine optimum pumping speed with the known mobility of the fluid. Optimum pumping speed at the sample means of pumping lead as quickly as possible, while avoiding the pressure drop pumping or pressure of the sample of formation fluid to the pressure dew point or below it. Therefore, the optimal pumping rate selected so that the pressure of the sample remained above the pressure at which condensation, allows to avoid formation in the sample dew. In respect of heavy oils perform a similar process, choosing the optimum pumping speed by determining the saturation pressure and setting the optimal speed is pumping on the basis of that the pressure of the sample should remain above saturation pressure, in a similar manner without reducing the pressure to a pressure drop of asphaltenes at the temperature of the reservoir in the well.

Dew point pressure and the saturation pressure can be defined in terms of the well or may be obtained by other means.

Brief description of drawings

To facilitate understanding of the nuances of the present invention the following is a detailed description of the example of its implementation, followed by the accompanying drawings, in which similar components and parts denoted by the same numbers, and in which are shown:

figure 1 is a diagram of the section of rocks, illustrating the working environment during implementation of the invention,

figure 2 - scheme of arrangement to implement the present invention, including complementary tools

figure 3 is a diagram illustrating the operation of the present invention in a typical embodiment, its implementation,

figure 4-13 - the number of graphs used to determine the pressure at which condensation and showing the relationship between the amount of passing light through the sample plotted on the Y-axis (power W) and in force at the test pressure plotted on the X-axis and expressed in pounds per square inch; decreasing the pressure capacity or the amount of light prohodjashei what about through the sample, increases to the pressure dew point at which the loss in the sample of asphaltenes and other solid substances begin to delay passing through the sample light, and its power is reduced,

on Fig graphic qualitative representation of reservoir testing with measurement of pore pressure in a known manner,

on Fig vertical projection system offshore drilling using the present invention,

on Fig - fragment of the drill string, made using the present invention,

on Fig diagram of the complete system that implements the present invention,

on Fig vertical projection variant implementation of the present invention with the use of cable technology,

on Fig graphics pressure changes depending on time and displacement of the pump, showing the nature of the pressure reduction, a specific theory using for calculation of certain parameters

on Fig - schedule pressure changes depending on time, which shows the initial part of the curve of pressure recovery for a breed with a moderately low permeability,

on Fig graphics describing the method for determining formation pressure using an iterative approximate estimates

on Fig - chart describing the method of finding the layer of the first pressure using data incomplete recovery pressure

on Fig - schedule of changes in pressure depending on the speed of the sampling fluid, illustrating the technique of calculations used in the method of determining reservoir pressure in accordance with the present invention,

on Fig is a graph illustrating the method proposed in the present invention,

on Fig image is placed in the bore of the sampler on the cable,

on Fig image pump double acting, intended for pumping formation fluid into the wellbore at the formation test to obtain not containing filtrate samples and pumping formation fluid into the receiving tank after obtaining a clean sample, and

on Fig image sampler that allows you to pump out from the rock qualitative sample fluid simultaneously measuring the change in mobility/permeability over time, providing a sample in a single-phase state with a low level of contamination of mud filtrate, while the physical characteristics of the received samples correspond to physical characteristics contained in the reservoir fluid.

Detailed description of exemplary embodiment of invention

Firm Baker Atlas developed a device for formation testing (sampler) RCITM(from the English. "Reservoir Characterization Instrument"), allowing to estimate the sample fluid, characterizes is the reservoir rock hydrocarbons. The device RCITMused to measure pressure in the rock-reservoir, as well as sampling of the manifold. These samples are processed in laboratories for studies of fluids on the basis of the pressure-volume-temperature (PVT) to determine thermodynamic properties and dependencies (PVT-data), which indirectly judged on the rock properties from which to take the sample. The quality of these data depends on the quality of the sampling device RCITM. One of the most difficult for sampling are near critical hydrocarbons, retrograde gas and gas condensate. A very important parameter from the point of view of the quality of the sample is the dew point pressure of the sample gas. If the sampling fluid pressure to decrease below the pressure at which condensation of the fluid in the rock-manifold, or the device may be released significant amounts of liquid hydrocarbons that greatly change the composition of the sample. One of the devices, used in conjunction with probowalem RCITMis the unit Sample ViewTMwith source and receiver radiation in the near infrared region (NIR) of the spectrum. The device Sample ViewTMis used to control sampling of formation fluids from the rock collector in situ borehole. Received by the device Sample ViewTMthe spectral characteristics of the ISR at a wavelength of 1500 nm or other interest wavelengths with a simultaneous increase of the sample volume in an isolated part of the device give an idea about the details of the changes in the phase state, for example, on the pressure at which the first drop of fluid (pressure dew point). On the graph showing the change in absorption capacity depending on pressure, notably a sharp decrease in absorption capacity under pressure dew point.

This proposed in the present invention, the technology improves the experience sampling in gas reservoirs. Currently on the market of oilfield services companies, there is no known technology to obtain data on the dew point pressure in the reservoir (natural) conditions. During any procedure sampling reservoir sample reservoir fluid extracted from the natural environment in which it was, i.e. reservoir, and placed inside the high-pressure chamber located in the downhole sampler, such as the device RCITM. This is achieved by pumping the sample fluid from the reservoir rock through the creation of on the border between the wellbore and the formation of differential pressure - depression on the formation, causing the flow of fluid in the receiving chamber of the sampling device RCITM. If the pumping speed is too great, creating a driving force of the differential pressure will lead to a drop in sample pressure below the pressure at which condensation. As soon as the pressure in the sampler, falling, walk on the pressure dew point, sample formation fluid may lose a significant amount of liquid condensate that significantly and permanently alter the composition of the sample. In this example implementation of the present invention in situ is determined by the dew point pressure, which is set to the optimum pumping speed of the device RCITM. Thanks to this optimal speed pumping with the help of the device RCITMfor a minimal time to take a sample of the highest quality, not allowing the pressure to drop to a pressure dew point.

In the oil industry technology sampling in-phase condition was introduced in order to provide laboratory analysis of PVT-data samples of the highest quality. PVT data are typically used for the economic valuation of the collector, as well as to calculate equipment and facilities for oil production. This technology looked very good against heavy and volatile oils, which are usually found in the reservoir in undersaturated conditions. In the case of retrograde condensate gas sampling was much more difficult. In order to take samples and retrograde condensate gas phase condition, it is useful to know the dew point pressure. Knowledge of the pressure at which condensation helps when IP is ladouanie even collectors with an unknown composition of hydrocarbons. The present invention first provides industry professionals a much-needed pressure at which condensation during sampling from the gas reservoir into the manifold. At a known dew point pressure determined in the borehole on site testing of the collector, it is possible to adjust the pumping speed so as not to get in the region of two-phase States in the diagram phase state, i.e. in the region of pressure below the pressure at which condensation. Therefore, compliance with this condition allows you to take a sample of fluid in really pristine condition, typical downhole conditions.

Figure 1 is a schematic geological cross-section 10 and the wellbore 11. The borehole is usually filled, at least partially, with a mixture of liquids, including water, drilling mud and formation fluids contained in the rocks through which the well was drilled. Such a mixture of fluid referred to as downhole fluids or liquids. The concept is "layer fluid" is used in future in respect of a particular formation fluids that do not contain any significant amounts of liquids and gases, which under natural conditions are absent in the corresponding host rock.

In the bore 11 at the end of the cable 12 evaluation of the eh device 20 for sampling formation fluid (sampler). To support cable 12 often use a pulley 13 mounted on the drill rig 14. The descent of the device and removed the cable is carried out with the help of the winch with mechanical drive running ground processor, for example, included in the equipment truck 15 for the maintenance of wells.

Figure 2 schematically shows an example run of the sampler 20 in accordance with the present invention. In a preferred execution of this sampler is a block of several adjacent sections connected end to end threaded bushings couplings 23 with an intermediate compressible rings. The composition of the block, suitable for carrying out the invention may include a hydraulic actuator 21 and a device 22 for extraction of fluids. Below the device 22 for extracting formation fluid is driven pump unit 24 with a large displacement for pumping the hydraulic lines. Below the pump with a large displacement is similar to the drive pump unit 25 with a smaller displacement of which is controlled in quantitative and qualitative respects, the respective device 300, described in greater detail by consideration of figure 3. As a rule, under the pump with a small displacement amount which is located one or more partitions of drives 26 with receiving tanks for samples. In each partition the drive 26 may be three or more receiving tanks 30 sample fluid.

The device 22 for extracting fluids contains a retractable probe 27 to the suction of fluid from the opposite from which side the shoes 28. As the probe 27 to the suction of the fluid, and the opposite the shoes 28 are nominated by the hydraulic actuator, positioned closely to the walls of the wellbore. In more detail the construction and operation of the device 22 to extract the fluids described in the patent US 5303775, whose description in full included in this description by reference.

As shown in figure 3, in this example, run the sampler contains the associated device 300 (aprooval) with two sapphire Windows, source 301 infrared radiation, preferably emitting at a wavelength of 1500 nm, a collimator 303, the receiver (detector) 306 and a computerized pump 302 with the means of pressure control. Below is an example sequence of actions during the formation test in the conditions of the well.

1. Include a pump device RCITMto clean coming from the rock formation fluid by pumping up until the formation fluids from the well zone practically will not contain impurities of mud filtrate. Wireline fluid is subjected to analysis in the near (Donovan is Oh) IR spectral region using the source 301, receiver 306 and computer 307. This process continues until the results of the analysis in the near IR region or at other wavelengths (i.e. technology Sample View) shows a minimum level of contamination of the fluid by the mud filtrate on the basis of steady-state or asymptotic behavior of the fluid properties in the near infrared region.

2. Sample 304 formation fluid pumped out of the rocks in step 1 isolate the device by means of valves, enclosing her in a regulated volume between window 305 and the pump 302.

3. The sample was allowed to stabilize at rest, ceasing pumping for five minutes.

4. In order to secure the onset of stabilization (recovery pressure control the pressure so that its rate of change not exceeding 0.2 pound per square inch per minute.

5. According to the receiver 306 is controlled absorption capacity of samples of hydrocarbons or the level of power flowing through her light, to ensure the stability of the reference line system.

6. In the receiver 306 and/or computer 307 zero absorption capacity in the near IR region or another region of wavelengths, or the value of power.

7. Computerized pump to operate to increase the sample with a speed of from 3 to 14 cm3/min, lowering the pressure acting on the sample in the regulated scope.

8 using your computer, or processor 307 build a graph of absorption ability or capacity of the transmitted radiation (transparency/absorption ability) from the pressure detection pressure dew point or saturation pressure.

In the present invention proposes a method and a device for determining the pressure at which condensation (dew point)at which the sample of formation fluid drawn liquid hydrocarbons. The dew point pressure is used as a reference value for determining the optimal rate of pumping during sampling, thus avoiding the loss included samples of hydrocarbons. The equations used to determine the Optimal speed of pumping based on the specified minimum allowable pressure greater than the pressure at which condensation or saturation pressure) and the known mobility of the fluid, as described below under "determination of the optimal speed of pumping based on the predetermined minimum permissible pressure".

Figure 4 contains the results of experiments to determine the pressure at which condensation described graphs figure 5-13. These charts show a set of curves 400 used to determine the pressure at which condensation and characterizing the change in the amount of passing light through the sample plotted on the Y-axis (power 410, W), hung is on the pressure 420, pending on the X-axis in the psi. Figure 5-13 it should be noted that with decreasing pressure registered by the receiver capacity or the amount of light passing through the sample increases up to a point corresponding to the pressure dew point (the point at which condensation)at which a drop of liquid hydrocarbons in the sample begins to slow passing light through the sample, resulting in less power. The pressure at which power starts to decrease again, there is pressure 440 dew point.

The present invention offers a downhole spectrometer, which allows to determine the dew point pressure for determining the optimal rate of pumping during sampling, which prevents the precipitation of asphaltenes in the sample of formation fluid. Samples under reservoir pressure, conclude in adjustable volume. In a regulated volume of lower pressure. First, the sample of formation fluid looks dark, as in the study of passes less light energy. But as the pressure decreases, and the sample pressure drops, it becomes more liquid, or less dense, it absorbs more light. Upon reaching the dew point pressure of the sample begins to darken, passing through less light energy, because it starts the fast drop of liquid hydrocarbons. Thus, the dew point pressure is the pressure at which passes through the sample to a maximum of light energy. The dew point pressure is introduced into the equation, allowing at the time of sampling to determine the optimum pumping speed with the known mobility of the fluid in order to prevent the pressure drop to the pressure dew point to avoid loss included samples of hydrocarbons.

Determination of the optimal speed of pumping based on the predetermined minimum permissible pressure

On Fig shows the rig in one embodiment of the invention. This drawing shows a typical drilling rig 202, which is understandable specialist way performed well 204. Rig 202 has a working column 206, which in this embodiment is a drill string. At the end of the drill string 206 is fixed drill bit 208 for drilling wells 204. The invention may find application with other types of work columns, it is also feasible when using cable equipment (cables, ropes, ropes), shown in Fig, columns precast pipes, columns flexible pipes, tubing and other small diameter pipes, such as pipe for lowering into the well under pressure. Rig 202 is installed on the drilling vessel 222, supplied by pipeline 224 connecting the drilling vessel 222 with the sea floor 220. VM is the extent, however, for the implementation of the present invention may be adapted to rig any configuration, for example ground installation.

If necessary, drill string 206 may be provided with a downhole motor 210. Part of the drill string 206 is located above the drill bit 208 usual control device, which may have at least one known from the prior art sensor 214 for measuring the conditions of the well characteristics well, chisels and rock collector. One useful feature of the sensor 214 is the determination of the direction, azimuth and orientation of the drill string 206 using a measure of the acceleration (accelerometers) or similar transducers. The layout of the bottom hole Assembly (BHA) also contains included aprooval or test layer 300 corresponding to that shown in figure 3. At a suitable point in the trigger column 206, for example, over the test 216 of the reservoir, is located telemetry system 212. Telemetry system 212 is used to transfer control signals and data between the surface and the test layer 216.

On Fig shows a section of the drill string 206. This section inside the downhole device is preferably included in the BHA, located near the drill bit (not shown). In the Tav device includes a block of data and source 320 energy to provide two-way communication with the surface and supply the deep components. In a preferred embodiment, the downhole device need only start signal from the surface, initiating the process of reservoir testing. In the future, all the functions of the control device are performed by the downhole controller and processor (not shown). The energy source may be a generator driven turbopump downhole motor (not shown), or any other suitable power source. There are also stabilizers 308 and 310 for centering section of the drill string 206 with the downhole device and the packers 304 and 306 to isolate part of the annular space. To allow continuous circulation of drilling mud above the packers 304 and 306 at a time, until the drill bit is not rotating, circulating valve is used, preferably located above the upper packer 304. For release of fluid from the test volume between the packers 304 and 306 in the upper annular space use a separate outlet or surge valve (not shown). The release of fluid through this valve reduces the pressure in the test volume that is required for reservoir testing with depression. It is also assumed that the pressure between the packers 304 and 306 can be reduced by sucking the fluid into the device or releasing the fluid into the lower annular space, but in any case, DL is the pressure reduction necessary in some way to increase the volume of medium in the annular space.

In one embodiment of the invention on the test layer 216 between the packers 304 and 306 is retractable sealing Shoe 302, preimages to the borehole wall 204 (Fig). The sealing Shoe 302 may be used without a packers 304 and 306, as it is fairly close contact with the borehole wall can be created by using a single Shoe 302. If the packers 304 and 306 are not used, it is necessary to create efforts, the holding sealing Shoe 302 to the borehole wall 204. The resulting seal creates near the sealing Shoe test volume located within the device and passing to the pump, without the use of volume between the packers. The composition of the downhole tool shown in Fig, also part of the device 300.

One of the ways to ensure the integrity of the test volume is more reliable fixation of the drill string 206. For zakalivanie the drill string 206 on the test layer in the design of the drill string 206 can be included managed retractable spacer elements 312 and 314. As shown in the drawing, in this embodiment, the spacer elements 312 and 314 built-in stabilizers 308 and 310. Spacers 312 and 314, which are at the ends should have a rough surface for coupling with the borehole wall, protects the structural elements of a soft material, t is the cue as the sealing Shoe 302 and the packers 304 and 306, from damage that can be caused by movement of the device. Of particular relevance is the use of spacer elements 312 has on floating drilling rigs, such as the setup shown Fig as caused motion movements can lead to premature wear of the seals.

On Fig schematically shows the device depicted in Fig, inside deep and surface equipment. For fixing the drill string 206 selectively retractable spacers 312 abuts the wall 204 of the well. Packers 304 and 306, are well known in the art, extend, clinging to the wall 204 of the well. In working condition packers divide the annular space of wells at three sites, rasamma between an upper annular space 402, the secondary annular space 404 and the lower annular space 406. An isolated part of the annular space (or simply an isolated area) 404 bordered by rock layer 218. On the drill string 206 with the possibility of selective or controlled extension in an isolated area 404 has a sliding sealing Shoe 302. As shown in the drawing, through a sliding sealing Shoe 302 passes the hydraulic line that connects the pristine layer of fluid 408 and sensors, such as sensor 424 pressure, creating what twistie 420 in the isolated annular space 404. To explore or to take a sample of it is fluid from the rock, it is preferable that the packers 304 and 306 were tightly pressed to the wall 204, and between the wall and the sliding element 302 formed a tight seal. The pressure decrease in an isolated area 404 before entering the sealing Shoe 302 in contact with the hole wall is the inflow of reservoir fluid in an isolated area 404. When such movement of formation fluids, when the sliding element 302 will come into contact with the hole wall, passing through the sealing Shoe 302 hole 420 will be open for receipt of pristine fluid 408. When drilling a directional or horizontal wells, it is highly desirable to control the orientation of the retractable element 302. In the preferred orientation of the retractable element must be directed to the upper part of the borehole wall. To determine the orientation of the retractable element 302 can use the sensor 214, such as accelerometers. Then, the sliding element can be set in a given direction, using techniques and not shown on the drawing tools that are well known in the art, such as directional drilling using deflecting sub. Device for drilling, for example, may include a drill string 206, rotating from the ground rotational drive (on which Artie not shown). For rotation of the column regardless of the drill bit can also be used downhole turbine motor (POS. 210 on Fig). Thus, the drill string can be rotated up until the sliding element is not located in a given direction, as measured by the sensor 214. At the time of testing ground rotational drive is stopped and the drill string 206 ceases to rotate, while the drill bit driven by a downhole turbine motor can continue to rotate.

The management of the test or assay of the reservoir preferably is carried out by the downhole controller 418. The controller 418 associated with at least one device 426 control volume system (pump) and an associated device 300. In a preferred embodiment, the pump 426 is a device with a small piston moving driven by a ball screw and stepper motor or other engine with the smooth control, due to its ability to consistently (in several stages) to change the volume of the system. In addition, the pump 426 may be a screw pump. When using other types of pumps in the system should also include a flow meter. To control the flow of fluid to the pump 426 in the hydraulic line 422 between the pressure sensor 424 and the pump is m 426 is located the valve 430. Test volume 405 of the device is the amount of space under the exhaust piston pump 426, including the amount of hydraulic lines 422. The pressure sensor is used to measure the pressure in the test volume 404. Here it should be noted that the formation testing can be just as full, if done with the retracted sealing the Shoe 302. In this case the volume of the system includes the volume of the middle annular space 404. This allows for a "quick test", saving time on the extension and retraction of the Shoe. Sensor 424 is connected to the controller 418, providing the feedback necessary for the operation of a closed-loop control system. Feedback is used to adjust settings, for example, pressure limit value for subsequent changes in volume. To further reduce the test time in the composition of the downhole controller includes a processor (not separately shown), and to save the data for future analysis and job default settings may be optionally provided by the database and the storage system.

When creating a depression in an isolated area 404, the fluid is diverted into the upper annular space 402 through balancing valve 419. In the channel 427 connecting the pump 426 with balancing valve 419, has an interior valve-valve 432. E. what do you need to take a sample of fluid, instead of switching through balancing valve 419 fluid can be prevented by using internal valves 432, a and 433b in receiving tanks 428 for samples that represent optional components of the device. A typical procedure of the fluid sampling involves extracting contained in tanks 428 fluid from the well for analysis.

In the standard version of the instrument designed for testing of formations with low mobility fluid (low permeability), the system, in addition to shown on the drawing pump 426 comprises at least one pump (not separately shown). The internal volume of the second pump must be much smaller than that of the main pump 426. It is assumed that the volume of the second pump must be one hundredth of the volume of the main pump. To connect these two pumps to the hydraulic line 422 may be used a conventional t-joint connector with valve-a valve controlled by the downhole controller 418.

In rocks with low permeability, the main pump is used to create the initial depression. The controller switches to the second pump to operate at pressures below the reservoir. The advantage of the second pump with a small internal volume is that the pressure recovery in such pump is faster than the pump a larger volume.

The result is data in the borehole can be sent to the surface to provide the operator of the drilling rig information about downhole parameters and conditions, or to test the validity of test results. The controller transmits the processed data is located in the well system bi-directional communication link 416. The downhole system 416 transmits data signals in a terrestrial communication system 412. There are a number of known means and methods of data transmission. To achieve the objectives of the present invention will be sufficient for any reasonable system. After the transmitted signal was adopted at the surface of the ground controller and the processor 410 converts the data and transmits the data to the appropriate device 414 output or storage. As described above, the ground controller 410 and terrestrial communication system 412 are also used to send commands to the beginning of test.

On Fig shows a variant implementation of the present invention using a descent on the cable (using cable technology) device containing the device 300. In the drawing bore 502 crosses the reservoir 504 rocks containing natural reservoir, which has a gas layers 506, oil, 508 and 510 water. In the well 502 near the rock formation, or formations, 504 is the descent on the cable device 512, supported by the armored cable 514. From the device 512 are spacer elements (paws) 312, if needed, to stabilize the device 512 in the well. The device 512 has two expanding packer 304 and 306, are able in order to divide the annular space of the borehole 502 with the formation of the upper annular space 402, hermetically isolated secondary annular space 404 and the lower annular space 406. The device 512 is sealing Shoe 302, capable of selectively eject. Spacers 312, the packers 304 and 306 and retractable sealing Shoe 302 have almost the same design that has been described when considering Fig and 17, so here is their detailed description is not repeated.

Telemetry equipment for the option with the use of the device on the cable is a downhole unit 516 bilateral relations associated with ground block 518 two-way communication with one or more conductors 520, passing in an armored cable 514. Ground unit 518 bilateral ties placed in the ground control device, which includes a processor 412 and the output device 414, such as have been described when considering Fig. The direction of the armored cable 514 when the shutter device in the barrel 502 wells by using the standard cable pulley 522. The composition of the device 512 includes a downhole processor 418 designed for process control reservoir testing using methods, which are discussed below.

Shown in Fig variant embodiment of the invention is useful for determining the contact points 538 and 540 between gas 56 and oil 508, as well as between oil 508 and 510 water along the borehole. To illustrate this option, use the outline of the layer 504 imposed schedule 542 variation of pressure with depth. The downhole device 512 includes a pump 426, several sensors 424, the associated device 300, the appropriate valves 430, 432 and, if necessary, catch basins 428 for samples, such as discussed above for the variant shown in Fig. These components are used to measure reservoir pressure at different depths in the well bore 502. Marked on the chart, the pressure values are an indicator of the density of a liquid or gas, which clearly varies from one fluid to the next. Thus, having multiple pressure measurements M1-Mnyou can obtain the necessary data to determine points of contact 538 and 540.

Below are the measurement strategy and methods of calculations to determine the effective mobility (k/µ) fluids in the rock-manifold in accordance with the present invention. The measurement duration is quite small, and the stability of calculation errors is provided for a large range of values of mobility. The initial depression is created at the speed of pumping (corresponding to the speed of retraction of the piston of the pump) from 0.1 to 0.2 cm3/s, which is significantly lower than the corresponding speeds, the usual currently used. Lower speed pumping reduces the chance of damage to the breed due to the migration of fine particles, reduce temperature changes, caused by expansion of the fluid inertial hydraulic resistance, which is when the permeability measurements of the downhole device may be significant, and it is easy to reach steady state, or stationary, the inflow of fluid into the sampling probe for any values of mobility, in addition to very low.

At low mobility fluid (less than approximately 2 MJ/SP) achievement of steady-state flow is not required. For these measurements, the compressibility of the fluid is determined by the initial part of the depression, when the pressure in the sampling probe exceeds the formation pressure. The effective mobility of fluids and pressure p* in the remote reservoir is determined by considering the following ways on the initial recovery phase pressure, which eliminates the need for a long final stage of the recovery pressure at which the pressure gradually reaches a constant value.

For higher values of mobility, when the mode of the steady inflow occurs during the depression quickly, the pump piston stop, followed by a rapid pressure recovery. For mobility, equal to 10 MJ/SP, and conditions adopted for the calculations of the s, described below as an example (including speed pumping, equal to 0.2 cm3/s)steady-state flow occurs when the depression corresponding to the pressure decrease of about 54 pounds per square inch below the reservoir. The subsequent restoration of the pressure to reservoir pressure plus or minus 0.01 pound per square inch), it only takes about 6 seconds. For large values of mobility of the depression on the formation is less and the recovery pressure is shorter (both behave inversely proportional to mobility). The mobility can be calculated by the velocity of fluid flow in a steady mode and the difference between the reservoir pressure and the depression. To check the thread on inertial hydraulic resistance can be used multiple speeds pumping. For pumping with lower rates and lower pressure drops may be necessary to Refine the pump.

As shown in Fig, after the packers 304 and 306 in an operational state, and the pump piston is in its initial position before performing a full stroke to the suction pump 426 is driven, preferably at a constant rate of increase of its working volume, or speed pumping (qus). The sampling probe and the connecting lines (pipelines), leading from it to Yes the chick pressure and the pump, form a volume of fluid in the measuring system, or "system volume", Vsistthat is filled with a homogeneous fluid medium, such as drilling mud. Up until the pressure inside the sampler exceeds the formation pressure, and the wall of the collector on the circumference of the wellbore is closed cake, the flow of any fluid in the downhole tool is impossible. Assuming the leakage of fluid through the packer, and the temperature drop caused by the expansion of the fluid when performing work, the pressure in the system according to the pressure sensor is determined by the expansion of the fluid equal to the volume of the pump, increasing during retraction of its piston. If aporsh- the cross-sectional area of the piston pump, x - traveled by the piston, the distance From the compressibility of the fluid and p is the system pressure, rate of pressure drop will depend on the volumetric expansion rate in accordance with equation (1):

Equation (2) shows that during retraction of the piston of the pump volume of the system increases:

and differentiation of equation (2) shows that:

Thus, substitution of the results of solving equation (3) in equation (I) and the conversion will receive:

At a constant compressibility equation (4) can integrate, obtaining the dependence of the pressure in the sampling probe from the scope of the system:

The pressure in the sampling probe can be attributed to the time of calculation of the dependence of the volume of the system from time to time by the equation (2). Conversely, if the compressibility is not constant, its mean value in the interval between any two values of the volume of the system is determined by the expression:

where the indices 1 and 2 do not necessarily mean measurements, following each other immediately. It should be noted that when creating a depression of the temperature is reduced, the apparent compressibility will be too small. The dramatic increase in compressibility may indicate a complication when pumping, for example, the supply of sand, the degassing of fluid or seepage through the packer or seal between the end of the sampling probe and the wall of the wellbore. In all circumstances, the calculated values of the compressibility will be false whenever the pressure in the sampling probe will be less than the reservoir pressure, resulting in a stream of fluid can flow into the sampling probe, creating the appearance of a noticeable increase in compressibility. However, it should be noted that the actual liquid media compressibility almost invariably slightly manufacture is consistent with the decrease in pressure.

On Fig shows an example of creating depression with decreasing pressure from the source of absolute hydrostatic pressure in the borehole, 5000 psi, up to (and below) the absolute reservoir pressure (p*) 608 comprising 4626,168 pound per square inch and is calculated on the basis of the following conditions is taken as an example:

is the effective radius of the sampling probe, riequal to 1.27 cm;

is a dimensionless geometric factor, G0equal 4,30;

- the initial volume of the system, V0equal 267,0 cm3;

the pumping speed during retraction of the piston, qusconstant and equal to 0.2 cm3/s;

the compressibility, C, is constant and equal to 1×10-5pound per square inch-1.

In the calculations it was assumed no change of temperature and leakage of fluid into the sampling probe through the seal. The pressure decrease when creating a depression presents depending on time or depending on the increase of the pump during retraction of the piston, which delayed respectively by the lower and upper axes of abscissa of the graph on Fig. The initial part of the curve 610 low pressure (above p*) is calculated by the equation (5) using the values of Vsistcalculated by equation (2). A further decrease of pressure passing through the reservoir pressure in the absence of flow in the sampling probe is redstavlena as curve 612 zero mobility. It should be noted that the entire curve is downward pressure with a "zero" movement of the fluid gently curved, due to the constantly increasing volume of the system.

Usually, when the pressure falls below p*, and the rock permeability is greater than zero, contained in the rock, the fluid begins to move in the sampling probe. If the equality p=p* the flow of fluid equal to zero, but with decreasing p he gradually increases. In real conditions, you may need some pressure drop to the clay crust has started to flake off, exposing the portion of the wall surface of the wellbore that is within the inner radius of the cuff, or packer, the sampling probe. In this case, the curve describing the change in pressure over time, will not go smoothly in the direction from the curve "zero flow", as shown in Fig, and will have a certain inflection. Until the rate of increase of the volume of the system (corresponding to the rate of increase of the working volume of the pump during retraction of its piston) exceeds the intensity, or rate of fluid flow in the sampler, the pressure in the sampling probe will continue to decline. To complement the insufficient inflow of the fluid contained in the volume Vsistexpands. While the inflow of fluid from the rock obeys the Darcy law, its intensity (flow of incoming fluid) is going to be to grow, moreover, this growth will be proportional to the differential pressure (p*-p). Ultimately, the speed of the inflow coming from the rocks of the fluid will be compared with the pumping speed, after which the pressure in the sampling probe will remain constant. This mode is known as steady state, or stationary, the influx.

The equation describing the steady flow of fluid, has the following form:

For the conditions given in respect Fig, the pressure drop in depression, provide flow in the steady state, p*-pmouthis 0,5384 pound per square inch for k/µ=1000 MJ/SP, 5,384 pound per square inch to 100 MJ/SP, 53,84 pound per square inch for 10 MJ/SP, etc. At a speed of pumping of 0.1 cm3/with these pressure drops are less than half, and at a speed of pumping 0.4 cm3/s - twice, etc.

As explained below, these depressions at high values of mobility pressure recovery after stopping the pump piston comes very quickly. The value of p* can be defined in a few seconds the pressure value, stabilised after the depression. In case of high mobility of formation fluids (k/µ>50 MJ/SP) pumping speed at the subsequent (-) depression(s)may need to be increased to obtain a sufficient negative pressure differential (p*-p). When the smaller the value is the second mobility pumping speed should be reduced, to make sure that the inertial hydraulic resistance (flow-Darcy) is negligible. In these cases, it is desirable to use a total of three different speed pumping.

Calculate the steady state is very desirable for large values of mobility, because of the calculation falls compressibility and mobility is determined by direct calculation. However, high-quality equipment: first, it is necessary to ensure the constancy of the speed of pumping and the ease of its regulation, and secondly, the differential pressure (p*-pmouthshould be small. It is desirable to have small piston driven ball screw and stepper motor to control depression during the approach mode of the steady-state flow at low values of mobility.

On Fig shown that delayed the graph the length of time the selection process fluid, characterized curve 614 for mobility of 1.0 MJ/SP and curves for smaller values of mobility, has not reached its steady state. In addition, for the curve 616 corresponding to the mobility of 0.1 MJ/SP and lower deviations from the curve corresponding to zero mobility, barely noticeable. For example, for 10 seconds, the magnitude of the pressure reduction in the mobility of 0.01 is D/SP only 1,286 pounds per square an inch smaller than in the complete absence of flow. You can assume the possibility of much larger than that of the deviations in pressure due to non-isothermal conditions or minor changes the compressibility of the fluid. The decrease of pressure with respect to R* more than 200-400 pounds per square inch is not recommended, as almost guaranteed a significant inertial hydraulic resistance (flow-Darcy), there is a possibility of formation damage due to the migration of fine particles, to avoid violations of the temperature regime becomes much more difficult, it becomes probable, degassing, and increases the power consumed by the pump.

On the length of time when R<R*, and to reach a steady-state flow of fluid there are three indicator speed 1) pumping speed, which characterizes the increase in the volume of the system over time, 2) the speed (intensity) of fluid flow from the reservoir into the sample probe, and 3) the rate of expansion of the fluid in the volume of the system, which is equal to the difference between the first two speeds. Assuming that the conditions are isothermal, filtering, breed obeys the law Darcy permeability of the rocks near the end of the sampling probe is not broken, and the viscosity of the fluid is constant, using the following equation linking the three discussed above until the of the motor speed, were calculated presents on Fig curves 618, 614 and 616 selection of fluid on depression for three values of the mobility of the fluid 10, 1.0 and 0.1 MJ/SP:

in which the flow of fluid from the rock in the sampler at time step n is calculated in accordance with the following expression:

Because to calculatein equation (9) requires a value of pnthat it is necessary to solve equation (8), we used an iterative method. For smaller values of mobility when using the pn-1as a first approximate estimate of p convergence of the results was fast. However, for the curve corresponding to 10 MJ/SP, for each time step required a much larger number of iterations, and if the mobility of 100 MJ/SP and above, this procedure has become unstable. You need to use smaller time steps and/or a much larger attenuation (or a method using solvers, not an iterative method).

To initiate the restoration of the pressure piston pump stop (or slow down). When the piston is stopped, the volume of the system remains constant, and the flow of fluid from the reservoir into the sample probe leads to that contained in the volume of system fluid is compressed, respectively, causing a pressure increase. For the measurements at high mobility, when calculations are performed only in the regime of steady-state flow, the determination of the compressibility of the fluid is not required. The pressure recovery is used only to determine R*, therefore, to restore the pressure piston pump stops completely. Under the conditions provided for Fig, the recovery time pressure up to R* plus or minus 0.01 pound per square metre is for curves 618, 620 and 622 corresponding to the mobility of 10, 100 and 1000 MJ/SP, respectively 6,0, of 0.6 and 0.06 seconds.

For measurements in low mobility when fluid selection mode steady-state flow is not achieved, the pressure recovery is used to determine both p *and k/µ. However, to carry out measurements throughout the recovery process pressure is not required. It takes a prohibitively long time, because the final segment of the curve recovery pressure is the driving force that brings the pressure to p*tends to zero.

The equation describing the recovery process pressure, assuming constant temperature, permeability, viscosity and compressibility, has the following form:

Rewriting and prointegrirowany this equality, we obtain:

where t0and R0accordingly, the time and pressure in the sampling probe at the time of beginning the La recovery pressure or at any arbitrary point on the curve of the pressure recovery.

On Fig presents a graph corresponding to the initial portion of the curve recovery pressure 630 for mobility 1 MJ/SP, which begins with the absolute pressure of 4200 pounds per square inch in the case of full recovery pressure reached the reservoir pressure p*equal to 4600 psi. This value is calculated from equation (11). In addition to the options shown on this figure, it should be noted that R0=4200 pounds per square inch.

Determination of reservoir pressure p* part-time curve of the pressure recovery can be seen in the example. Table 2 presents data of a hypothetical experiment. The problem is to accurately determine the value of R*, get that any other way is not possible. To obtain R* empirically would require at least 60 seconds instead of 15 seconds, shown in Fig. The only hypothetically known information are system values given for Fig, and volume of the system Vsistequal 269,0 cm3. The compressibility, C, is determined using equation (6) according to the data obtained at the beginning of the downward pressure from the hydrostatic pressure in the well.

Table 2
These hypothetical recovery on the means for a reservoir with a moderately low permeability
Time t-t0withAbsolute pressure p, psiTime t-t0withAbsolute pressure p, psi
0,000042007,10024450
0,966642508,42014475
2,0825430010,03544500
3,4024435012,11794525
5,0177440015,05314550
5,98434425

The first group of parameters in the right part of equation (11) and the previous logarithmic group can be considered to restore the pressure as the time constant τ. Therefore, by adopting this definition and transforming equation (11), we obtain:

A graph showing the depending the left side of equation (12) from (t-t 0), is a straight line, for which the tangent of an angle equal to 1/τ, and cut, cut on the coordinate axis, is equal to zero. On Fig shows the graphs built by the data in table 2, using equation (12) under different assumptions, the values of R*. This figure shows that only when the exact value of absolute pore pressure equal to 4600 psi, you can get direct 640. In addition to assumptions smaller than the exact value p* (curve 646), the slope of the curve (angle) at an earlier smaller than later. Conversely, too high for assumptions (curves 642 and 644), the slope of the curve in the earlier sections of more than later.

These observations can be used to create a quick way to find the exact values of R*. First, we calculate the average value of the slope of the curve at an arbitrary early interval of the data presented in table 2. The calculation of the tangent of the angle starts at t1and R1and ends at t2and p2. Then calculate the average tangent of the angle of inclination of the later portion of the curve for the later interval data of the specified table. Subscript indices for parameters at the beginning and end of this calculation are respectively 3 and 4. Now divide the tangent of the angle of the Rann is the second portion of the curve to the tangent of the angle of inclination of the later portion of the curve, having coefficient R:

Suppose that at the beginning of the early portion of the curve we take from table 2, the second set of experimental points: time 2,0825 C and absolute pressure of 4300 pounds per square inch. Suppose also that at the end of the early portion of the curve, the beginning and the end of the later portion of the curve, with subscripts 2, 3 and 4, we take from table 2, respectively, 5-th, 9-th and 11-th sets of experimental points. If now we assume that p* is equal to 4700 psi, then we substitute these numbers into equation (13) and the calculated value of R is equal to 1,5270. Because this value is greater than one, the guess was too high. The results of the evaluation of this and other assumptions relating to the value of R* using the same data as discussed above, is presented in the form of the curve 650 on Fig. The exact pressure value p*equal to 4600 psi, corresponds to the ratio R=1. These calculations can easily be incorporated into the solver, which will quickly lead R* to its exact value, not system charts. By setting the exact value of p*, the mobility is calculated based on the transformation of equation (11) using the compressibility obtained during the initial depression relative to hydrostatic pressure.

In General, for real data when calculating the value of p*, then /µ should be avoided early interval data recovery pressure. This is the most rapid phase of the recovery process pressure, high differential pressure, has the highest thermal distortion of the data caused by heat compression, and also the greatest likelihood that the flow of incoming fluid will not obey the law Darcy. After determining the values of R* as described above the entire set of data should be presented graphically in accordance with Fig. If in the initial part of this schedule increases the slope of the curve over time, after the curve gradually straightens up, it may be a good indication that the flow of fluid at higher differential pressures is not subject to the law Darcy.

Another method proposed in the present invention, will be explained below with reference to Fig. On Fig presents the relationship between the pressure 602 in the device and the speed of qPP604 inflow of fluid from the reservoir, as well as the impact of the exit velocity of flow above and below certain thresholds. The Darcy law says that the pressure is directly proportional to the velocity of fluid flow in the reservoir. Thus, if we plot the dependence of pressure on the speed of movement of the piston during the pumping, at a constant pressure in the device during movement of the piston with some given velocity of such a graph will have formdialog. Similarly, a graph of the relationship between the velocity of flow and stable pressure in the area between some lower and upper limits will be in the form of a straight line, usually with a negative slope (m) 606. The tangent of this angle is used to determine the mobility (k/µ) of the fluid in the rock formation. To obtain the rate of fluid flow from the reservoir equation (8) can be converted as follows:

Equation (14) is true for conditions of the unsteady flow and steady. The rate of flow from the reservoir qPPcan be calculated by equation (14) for the conditions of unsteady flow, when the parameter is known quite accurately, that allows to define the points to plot, shown in Fig.

Conditions steady-state flow will simplify equation (14)as (Rn-1-Rn)=0. In the steady state inflow to determine points a straight-line segment of the graph on Fig you can use the known parameters of the device and the measured values. On this segment in the equation, you can substitute the pumping rate of qus. Then, using qusin equation (9), we obtain:

In equation (15) m=(p*-pmouth)/qus. The units for k/µ is the MD/SP, for absolutely what about the pressure p nand p* - pounds per square inch, for ri- RM, for qPPcm3/s, for Vusand V0cm3for With - (psi)-1and for t seconds. Each value of pressure on the straight-line segment represents the settled pressure at a given rate of flow (or speed suction).

In practice, care of the graph away from direct near zero speed of the inflow of reservoir fluid (filtrate) can be an indicator of a penetration device of the drilling fluid (flow rate approximately equal to zero). At high intensities of the inflow of this deviation is usually associated with a mismatch between the inflow to the law Darcy. However, the reservoir pressure can be defined by extending a straight line segment to the intersection with the ordinate axis corresponding to zero speed selection. The calculated value of the reservoir pressure p* should be equal to the measured Plast pressure within a negligible margin of error.

Task hydrostatic reservoir testing is determining the pressure in the rock collector and determining the mobility of the fluid in the collector. Correction of the movement of the piston of the pump to obtain constant values of the measured pressure (zero slope) for a particular method gives the necessary information to determine the pressure and is moveable is here regardless of the method restore pressure to stable level using constant volume.

Certain advantages of this method are the quality control due to the automatic validation of test results by observing a stable recovered pressure, and quality control by comparing the mobility determined in the process of pressure reduction, mobility, defined in the recovery process pressure. In addition, if it is not possible to use the results of testing, providing pressure recovery (in case of loss of device integrity or excessive recovery time pressure), the pressure value p*.

On Fig presents an example of a graph of change of pressure in the device at the time when you use another method proposed in the present invention. This graph illustrates the method, involving the change of speed of movement of the piston when creating a depression on the basis of the slope of the pressure change over time. Sensor data received at any point in the test, can be used together with equation (14) to generate a plot similar to that shown in Fig, or typing in the computer-controlled automated solvers. Separate measurements characterizing the steady-state pressure at various speeds of flow, m is should be used for validation tests.

The implementation proposed in the invention method begins with the deployment of the instrument IPA, similar to the one shown on Fig, or descent on the cable of the device, similar to the one shown on Fig. First, the sampling probe device 420 is pressed against the wall of the wellbore, and in test volume 405 is essentially only the drilling fluid, the pressure of which is equal to the hydrostatic pressure in the annular space. On a command transmitted from the surface at time 702 begins phase I trials. Next steps it is preferable to make running the downhole controller 418. Using this controller for controlling the suction pump 426 with the piston, the pressure in the test volume is reduced at a constant speed by setting the speed of retraction of the piston of the suction pump to the preset value. For measuring parameters of at least the pressure of the fluid in the unit intervals of time used sensors 424. These intervals set so that in each phase of testing to produce at least two dimensions. Additional benefits can be obtained by measuring the respective sensors system capacity, temperature and/or rate of change of the volume of the system. Phase I determines the compressibility of the fluid in the device, considered applying to enter the methods of calculation.

Phase II testing begins at time 704, when the pressure in the device drops below the reservoir pressure p*. The slope of the pressure change, due to the early receipt of the formation fluid in the test volume. This change of angle determines using the downhole processor to compute the angle of the curve based on the measurement results obtained for two period of time within one phase. If the rate of absorption of fluid maintained at a constant level, the pressure in the instrument sought would be set at some level, a smaller p*.

At a given point in time 706, the absorption rate increases, taking the test in phase III. Due to the increased speed of the suction pressure in the device is reduced. With decreasing pressure the rate of flow of formation fluids into the device increases. The pressure in the apparatus will tend to be smaller than that to which it sought in phase II, because the absorption rate in phase III than in phase II. When the results of interval measurements show that the pressure in the device is approaching stabilization, the absorption rate at time 708 again reduce the starting phase IV trials.

Then the absorption can be slowed down or stopped so that the pressure in the device began to grow. When the pressure starts aviateca, the angle of slope of the curve will change sign, and this change gives rise to phase V (point 710), then the absorption rate increases to stabilize the pressure. About stabilizing pressure is judged by the fact that the results of measurement of the pressure curve pressure becomes zero. Then the speed of retraction of the piston is reduced, allowing the pressure in the phase VI, starting at time 712, grow up until it stabilizes again. After the pressure has been established, phase VII, starting at time 714, the piston of the suction pump is stopped and the pressure in the device is allowed to grow as long as it is not located at the level of the reservoir pressure pPL. After this test is completed, the controller aligns the pressure in the test volume 716 of the hydrostatic pressure in the annular space. Now the device can be set in the retracted position and move to a new location or removed from the well.

The value of the established pressure obtained in phase V (starting at point 710) and phase VI (beginning at point 712), and the corresponding speed of the piston are used by the downhole processor to build a curve similar to that shown in Fig. On the discrete results of the measurements, the processor calculates the pressure p*. Then the calculated value of R* is compared with smaranam reservoir pressure p PLreceived by the device in phase VII (the starting point 714) test. This comparison is performed to check the validity of the values measured reservoir pressure pPLthat allows you to do without separate control tests.

Other ways of carrying out similar tests with one or more of the techniques discussed above method are also covered by the patent claims of this invention. Continuing to consider pig, it should be noted that the implementation of the method in another embodiment, including phase I-IV, and then phase VII. This option is useful when testing the rock layers of moderate permeability, when it is necessary to measure formation pressure. In this embodiment, the profile of the percolation phase IV is usually slightly different from those shown. Phase VII begins when the measurement results show that the slope of the curve of pressure was almost zero (cut 709). Before moving the device in this embodiment is also necessary operation 716 equalize the pressure.

Another variant implementation of the present invention provides for the conduct of phase I (beginning at point 702), phase II (beginning at point 704), phase VI (beginning at point 712) and phase VII (starting at point 714), and operation 716 adjustment pressures. This variant of the method used in the rock strata PTS is ery low permeability or loss of tightness of the sampling probe. In phase II, the deviation of the curve is not as pronounced as shown in the graph, so straight section 703 of phase I, obviously, should go significantly below the reservoir pressure pPL.

On Fig shown aprooval layers on the cable that is deployed in the borehole without the use of packers. Fig illustrates the implementation of the present invention from the point of view of the device of the device or tool for formation testing, also called probowalem layers. On Fig given image probovatel layers, taken from patent US 5303775 (Michaels, and others), the content of which in full is included in this description by reference. In the patent US 5303775 the proposed method and the device used in the selection of the sample contained in the rock of the fluid in the undisturbed phase condition using downhole probovatel reservoirs for delivery of this sample in a sealed receiving tank in the laboratory complex. The pressure in one or more placed in the tool receiving tanks for sampling the equalized with the fluid pressure in the borehole at the level of the studied reservoir, and these tanks are filled with samples of formation fluids so that during filling of the receiving tank pressure formation fluid is maintained within a specified interval greater than the saturation pressure of the sample fluid. Priem the second tank contains located inside the free-floating piston, which divides the receiving tank to the chamber for placing the sample and the camera equalize the pressure in which is maintained a pressure acting in the wellbore. Receiving tank equipped with a shut-off valve that allows you to maintain the pressure of the sample fluid after extraction probovatel formation from the borehole for transportation to the laboratory complex. To compensate for the reduction of pressure during cooling of the inlet tank and its contents mechanism of the reciprocating pump of this device is made with the possibility of increasing the sample pressure to a level above the saturation pressure by a sufficient margin, so if there is any pressure drop due to cooling of the pressure of the sample fluid does not drop below its saturation pressure.

On pig picture shown with the block diagram, which shows performed in accordance with the invention, the formation tester located in the bore at the level of the test layer contributes through its sampling probe with a reservoir rock for testing and obtaining one or more samples contained in the rock fluid. On Fig in vertical section shows the area of the borehole 10, passing in the area of rocks 11. Into the well 10 on the cable 12 is lowered, the device 13 for sampling and measurement (aprooval-meter). This prioristic from the power hydraulic system 14, section 15 of the sample fluid and section 16 of the sampling mechanism. Section 16 of the sampling mechanism includes a selectively retractable clamping Shoe 17, leaning on the wall of the drilled hole, selectively sliding the sampling probe 18 to the inlet of the device of the fluid, and the pump 19 bilateral actions. If necessary, the pump 19 may be located above the sampling probe 18.

When working device 13 for sampling and measurements have in the borehole 10, raising or lowering it to the cable 12 by means of a winch drum which is wound the cable 12. When the device 13 will enter the zone of the investigated layer, information about the position of the device on the depth obtained from the pointer 20 depth, is entered in the processor 21 of the signal processing and recording unit 22. Electrical wires of the cable 12 in the device 13 are transmitted to the electrical control signals from the control circuit 23, including not shown on the drawing processor.

These electrical control signals is activated hydraulic pump power hydraulic system 14 that provides hydraulic power for operation of the device, in particular, to move the clamping Shoe 17 and sampling probe 18 across the axis of the device 13 to the stop in the breed 11, and the pump 19 bilateral actions. Then the element to the inlet of the fluid, i.e. the sampling probe, 18 you can enter in contact with the fluid breed 11 by passing from the control circuit 23 electrical control signals to selectively operate located in unit 13 solenoid valves to obtain a sample of fluid that may be contained in the breed. The structure of this device is the device 300.

On Fig depicts the pump is double acting, used for pumping formation fluid into the wellbore to obtain a sample that does not contain leachate, as well as for injection does not contain leachate sample fluid into the receiving tank. On Fig shows part is made in accordance with the invention, a multifunction tester layers representing schematically a piston pump and two located in the instrument receiving reservoir for fluid samples. Fig and 26 taken from patent US 5303775, where they are described.

As can be seen in partial schematic form in cross section, shown in Fig, the device 13 for formation tests (the test or probovatel), shown in Fig, is a piston pump unit of a double-action, marked on Fig common position 24. In the case of the device 13 also includes at least one, and preferably two, of the receiving tank 26 and 28 for samples, which optionally may have od is nekovee performance. In the piston pump unit 24 has two opposite chambers 62 and 64 through supply channels 34 and 36 are communicated with the respective receiving tanks. Control the release of fluid from the respective chambers in the supply channel of the selected receiving tank 26 or 28 is an electric trepalium valves 27 and 29 or any other suitable valve mechanism to selectively fill the receiving tank. As shown in the drawing, the respective pump chamber can communicate with the breed lies beneath the surface of the investigated reservoir through the feed channels 38 and 40 chambers formed is shown in Fig sampling probe 18 and having a corresponding valve control. The feed channels 38 and 40 may be provided with check valves 39 and 41, if necessary, discharging the pressure in the chambers 62 and 64 when excessive pressure increase. Potentiometer 47 to measure the translational motion tracks the position of the pistons 58 and 60 and the speed of their travel, and then when the known size of the piston cylinder can determine the volume pumped out over time.

The present invention provides performance analysis of the rate of flow of formation fluids (ASPF) at the end of each stroke of the piston on the suction side of the pump is the process of restoring pressure to determine the mobility, compressibility and coefficient of correlation. The invention allows the construction schedule of changes in mobility over time, which can be delivered to the customer of works on formation test as a measure of confidence that the sample collection is complete. According to OSPF graph of pressure dependence of the speed of flow of the fluid from the reservoir. The closer the plot to a straight line, the higher the correlation coefficient. Obtaining the correlation coefficient over 0.8 is an indication that the pumping speed is in good agreement with the ability of the rock to give the layer of fluid.

Graph of pressure against time allows you to set pressure P* as a result of solving the equation P(t)=P* - [reciprocal mobility] × [velocity of flow from the reservoir]. This graph has a negative slope angle and intersects the vertical axis y, which delayed the pressure P, at the point corresponding to the value of R*. Reverse behaves depending on the speed of the inflow of reservoir fluid mobility. The degree of approximation of the graph to a straight characterizes the correlation coefficient. If the correlation coefficient falls below 0,8, it shows the complication of the process of pumping. The invention allows the operator to signal the up arrow to increase the speed of pumping, if the breed is able to give the fluid in od is opasna state with a higher speed pumping, or signal the down arrow to decrease the speed of pumping, if the pumping rate exceeds the ability of the rock to give the fluid in a single phase condition.

The working volumes of the chambers 62 and 64 are known in advance, and the position and speed of movement of the pistons 58 and 60 are measured by the potentiometer 47, resulting in OSPF is held at the end of each stroke of the pump is double acting. Because the absorption rate and the working volume of the known position of the piston and the speed of its change, as well as the size of the chambers 62 and 64, the volume that creates depression, also known or can be calculated.

It is true that Psaturation-P* = -(1/mobility) (speed of flow from the reservoir). The difference of Psaturation-R* represents the amount of pressure that separates the sample from the transition in two-phase state. Using OSPF, you can determine the mobility of the formation fluid based on the calculated rate of flow from the reservoir, and the corresponding pumping rate of qddin equation (16) is calculated in such a way as to be consistent with the rate of flow from the reservoir, as discussed below. The controller downhole tool automatically adjusts the pumping speed, sending feedback signals to control the hydraulic valves of the pump, or sends the operator a signal to adjust the speed of ODAC and thus, in order to achieve the optimal speed of pumping consistent with the mobility of the formation fluid.

When in the process of pumping the piston 58, 60 of the pump is double acting completes its working stroke, the suction side of the pump is OSPF. Before the piston 58, 60 of the pump will begin to move, using ISPF based on the pressure recovery of formation fluids at the end of the corresponding stroke of the pump stroke of its piston) for the pumped fluid are determined compressibility, motility and the correlation coefficient. Thus provided by the present invention perform ASPP during pumping allows for the selection of single-phase samples to obtain data on the potentiometer and the size of the pump the exact amount in which you are creating the depression, and the rate of absorption. Obtained by OSPF data in relation to mobility, compressibility and graphs of pressure differentials provide validation of assay data and hydrodynamic testing. Therefore, the holding OSPF in the process of pumping ensures that for accurate hydrodynamic testing and obtaining single-phase samples, characterizing wireline fluid used properly-speed suction.

In accordance with the existing option of the present invention a device and method for controlling pumping of lastovich fluids from oil - and gas-bearing rocks and ensuring quality control of pumping by applying the above method ASPF after each stroke of the pump. OSPF is held on the suction side of the pump control process recovery pressure of formation fluids provided by the invention using OSPF to calculate mobility, compressibility, coefficient of correlation and p* time. Proposed in the invention method enables to analyze the measurement results obtained by the formation tester on the cable against the formation pressure and mobility of formation fluids, by applying the above method ASPF after each step shown in Fig pump double acting. With the help of test layers usually are pumping formation fluid into the wellbore, or pumping formation fluid, prior to sampling to ensure the absence of mud filtrate. Pumping fluid to obtain a clear filtrate samples can last for hours. In addition, the important point is the need to maintain the most effective pumping speed, avoiding complications such as blockage of the downhole device, the leakage of the packer, sand or rock. In accordance with the invention OSPF is conducted with respect to process parameters pumping using a known displacement chambers 62 or 64 of the pump is double acting. In a typical embodiment of the invention the processor, which fitted well with the PRS, informs the operator in relation to the desired speed and whether the pumping speed to increase or decrease, displaying on a screen located on the surface of the operator of the arrow "up" or "down" or stop pumping, either automatically adjusts the pumping speed or stops the pumping for elimination during the study revealed when pumping complications.

If the pumping is without complications, the correlation coefficient, defined by OSPF for a series of continuously following each other cycles of the pump is relatively high, i.e. more than 0,8-0,9, but in case of complications, the correlation coefficient according to OSPF fall again. Compressibility determined by OSPF, is used as an indicator change type of fluid during pumping. By constantly monitoring the compressibility of the reservoir fluid, you can quickly notice a change in the type of fluid pumped from the reservoir. Thus, if the compressibility of the mud filtrate and the compressibility of the reservoir fluid, there is a significant difference, it is relatively easy to control the degree of purification of reservoir rock from leaked in her mud filtrate as the compressibility will vary from values indicating the mud filtrate, to the value indicating the layer of fluid. For measuring the ing the purity of a sample of formation fluid, the results of control measurements of the spectral optical density in the near-IR region, combined with the compressibility according to OSPF.

The present invention provides for the use of OSPF based on the known volume of the chambers 62 and 64 of the pump is a double-action or pump chamber unilateral action. Method OSPF can be used in relation to one stroke of the pump or of several such cycles, calculating mobility, compressibility and coefficient of correlation for the corresponding single clock cycle or multiple cycles. On the basis of specific data ASPF mobility of the fluid in the rock, the invention provides for the calculation of the optimal speed pumping to maintain pressure flow level above the saturation pressure, and informing the control device engineer about whether to change the parameters of the process of pumping to achieve the optimum pressure, or automatically adjust the speed pumping to achieve the optimum pressure at which the pumping speed is consistent with the ability of the rock to give the contained fluid. The invention provides for continuous monitoring during the process of pumping for mobility, compressibility and coefficient of correlation, based on OSPF on the subject of significant changes in the above variables to determine the ability of the breed to give fluid or detection of complications when pumping.

Method OSPF allows you to define near the banks of fluid flow from the reservoir for subsequent analysis. At the heart of this analysis lies in the following equation:

In the right part of equation (16) the second term in brackets - (CsistVsist(dp(t)/dt)+qdd) - fully represents the rate of fluid flow from the reservoir, calculated by correcting the moving speed of the piston (qddon the basis of the parameters and conditions downhole tool. Withsistis the compressibility of the fluid in the hydraulic line of the device, and Vsist- volume hydraulic lines, G0- this is a geometric factor, and riis the radius of the sampling probe.

The positioner piston pump is shown in Fig potentiometer 47 to measure the translational motion. Potentiometer for measuring the parameters of the translational motion is used to track how the piston position and speed of its movement. On this curve, using the cross-sectional area of the piston pump in cm, calculate the volume (DDV), which creates a depression, and pumped volume (PTV). Curve evacuated volume (PTV-BB) is constructed from data measured in cm3. OSPF you can use when pumping with pump a small amount, equal to 56 cm3when the volume of the pump chamber are shown on the graph evacuated volume (PTV).

Mobility and compressibility of the fluid is changed at each step of us who sa but their values are very close. Mobility increases only slightly. The results ASPF obtained for three cycles of the pump, taken together, i.e. in combination with each other, in fact, represent the values of the compressibility and mobility, averaged over three work cycles. The above example shows that OSPF succeeds in relation to the process parameters pumping when using the RCI device (Reservation Characterization Instrument) with pump type "BB" volume 56 cm3and using curves evacuated volume (PTV). OSPF is performed for each clock cycle, either to save time calculations can be carried out in relation to several measures taken together.

The saturation pressure of formation fluid or a mixture of formation fluid from the filtrate can be assessed by well test fluid expansion or on the basis of known data extracted from databases and representing the correlated values. After by ASPF received the mobility of the fluid in the rock formation, using OSPF calculates the maximum pumping rate that can maintain pressure when pumping at a level exceeding the saturation pressure. In addition, any significant change in the value of compressibility according to OSPF, for example, half of the order or on the order involves changing the type of the post is non in the device of the fluid, that will be an indicator of clearing rocks from contamination (in the near-wellbore area of the formation).

In accordance with the present invention from the total number of cycles completed by the pump when creating depression, few are chosen, and on the basis of the calculated speed of the suction receive data ASPH. For the parameters of the process of pumping the analyzed interval is selected based on the number of cycles of the pump, and not the rate of absorption. The invention provides for pumping at a variable number of cycles of the pump, and in the beginning of the process selects a few small bars, for example two or three steps, with a gradual increase in the number of cycles of the pump to a specified maximum, for example, ten cycles, which in this example corresponds to about 500 cm3drained fluid.

On Fig schematically presents the sampler. The present invention allows the use of OSPF when pumping from the rock sample fluid. Execution OSPF allows us to calculate the characteristic changes of compressibility, permeability and mobility over time. Tracking changes in permeability over time allows us to estimate or determine the degree of contamination of the sample filtrate. Since the compressibility of the reservoir fluid is greater compressibility of the filtrate, compressibility curve steadily goes down and as the pumping fluid from the reservoir rock and disappearance the Oia impurities of the filtrate in fluid asymptotically rectified at some fixed value.

As shown in Fig, wireline fluid pumped from the rock 2010 pump 2018. Coming from rock 2010 the fluid is directed either to the outlet 2012 in the wellbore for pumping fluid to clean from dirt or in the receiving tank 2020 for samples, for storing samples in single-phase state, and is taken as a sample 2021, once it is established that it does not contain impurities. The present invention provides the ability to monitor the dynamics of changes of compressibility, permeability and mobility in real time, which allows you to control the quality of the selected sample so that the sample fluid remained in the same condition in which fluid was in the breed.

On the suction side 2014 pump 2018 pressure falls below the formation pressure, causing the flow of formation fluids from the rock into the pump 2018. The magnitude of decrease in pressure below the formation pressure at the suction side of the pump is set in accordance with the present invention. In particular, this pressure difference is set so that the pressure in the sample fluid does not drop below the saturation pressure, or the pressure at which condensation. When determining the magnitude of the pressure drop on the suction side of the pump stem also from the condition that the pressure in the sample fluid must not fall below the pressure drop asphaltenes, blah is odara which the sample fluid remains in a liquid state, in which the fluid was in the rock formation. Accordingly, there is a first differential pressure, which is set so that the pressure when pumping has not fallen below the saturation pressure and has not begun the formation of gas bubbles. There is also a second differential pressure, which is set so that the pressure when pumping has not fallen below the pressure at which the reservoir fluid begins precipitation of solid substances, such as asphaltenes. Thus, using the above-mentioned first and second pressure differentials delivers samples of formation fluids without phase change associated with the formation of additional gases or solids. The first and second pressure drops are determined by the saturation pressure and pressure drop of asphaltenes obtained by simulation or analysis of previously obtained information about the reservoir. Control of the cleaning process samples of fluid from the filtrate ensures that the sample of formation fluid does not contain leachate or contains it in a minimal amount, so the composition of the sampled formation fluid authentically replicates the composition of the formation fluid, when it is contained in the rock formation.

In yet another embodiment, the present invention offer in the way it is implemented in the form of a set of executable in the computer, the commands, recorded on a machine-readable data carrier, comprising a persistent storage device (ROM), random access memory (RAM), CD-ROM (CD-ROM), flash memory or computer-readable media of any type whatsoever, known or unknown at the present time, and in the performance of the computer implements proposed in the invention method.

Although in the above description were considered specific examples of the invention, a specialist should be obvious various changes may be made in the variants of the invention. Any such changes are subject set forth in the claims of the patent claim considered as covered by the above description. In this description have been quite widely reported examples of the more important features of the invention, to facilitate understanding of the subsequent detailed description and evaluation of the contribution of the invention in the prior art. Of course, there are also additional features of the invention which will be described later, and is available in the accompanying claims.

1. Device for pumping sample of formation fluid containing a receiving chamber for samples which is connected with the receiving chamber of the pump in communication with the sample means of measuring the pressure and pricheski analyzer, optically associated with the breakdown of providing a pressure drop in the sample by determining the pressure at which occurs the extremum quantity of light passing through the sample.

2. The device according to claim 1, also containing the processor, based on the pressure at the extremum quantity of transmitted light to determine the optimum pumping speed at which the pumping tests performed as fast as possible without falling pressure in the sample below the value corresponding to the dew point pressure and/or saturation pressure.

3. The device according to claim 1, also containing the processor, allowing to determine the dew point pressure for the sample of formation fluid.

4. The device according to claim 3, in which the processor makes it possible to determine the optimal pumping rate based on the pressure at which condensation.

5. The device according to claim 1, also containing the processor, allowing to determine the saturation pressure for the sample of formation fluid.

6. The device according to claim 5, in which the processor makes it possible to determine the optimal pumping rate based on the saturation pressure.

7. The device according to claim 1, also containing the processor, allowing to determine sample formation fluid pressure drop asphaltenes.

8. The device according to claim 7, in which the processor makes it possible to determine the optimal pumping rate based on pressure drop of asfal is ENES.

9. System for determining the optimal speed of pumping of sample formation fluid containing downhole sampler having a receiving chamber for sampling formation fluid, a device for pumping formation fluid into the intake chamber, a device for measuring the pressure existing in the inlet chamber to the sample reservoir of fluid associated with a receiving cell increase, allowing to lower the pressure existing in the inlet chamber on a sample of formation fluid, and an optical analyzer for analysis of sample formation fluid by determining the pressure at which occurs the extremum of electromagnetic energy passing through a sample of formation fluid.

10. The system according to claim 9, comprising a processor, based on the pressure at the extremum of the power of electromagnetic energy to determine the optimum pumping speed at which the pumping tests performed as fast as possible without falling pressure in the sample below the value corresponding to the dew point pressure and/or saturation pressure.

11. The method of determining the rate of pumping of the sample of formation fluid, which consists in the fact that in the chamber pumped to a sample of formation fluid, measure the pressure acting in the chamber on a sample of formation fluid, increase the volume of the chamber and examine a sample of formation fluid by determining the pressure at which oterom comes extremum of electromagnetic energy, passing through a sample of formation fluid.

12. The method according to claim 11, in which the pumping speed set in such a way as to maintain the depression on the formation based on the pressure of extreme electromagnetic energy to more quickly perform pumping tests without the pressure drop in the sample below the value corresponding to the dew point pressure and/or saturation pressure.

13. The method according to claim 11, in which to sample formation fluid determine the dew point pressure.

14. The method according to item 13, which is based on the pressure at which condensation determine the optimum pumping speed.

15. The method according to claim 11, in which to sample formation fluid determine the saturation pressure.

16. The method according to clause 15, which on the basis of the saturation pressure determine the optimum pumping speed.

17. The method according to claim 11, in which to sample formation fluid determine the pressure drop of asphaltenes.

18. The method according to 17, in which on the basis of the pressure drop asphaltenes determine the optimum pumping speed.

19. The method of determining characteristics of a sample of formation fluid, which consists in the fact that in the chamber pumped to a sample of formation fluid, measure the pressure acting in the chamber on a sample of formation fluid, increase the volume of the chamber, examine a sample of formation fluid by determining the pressure at which nastupayucshim electromagnetic energy, passing through a sample of formation fluid, determine at least one characteristic of the sample of formation fluid selected from the group consisting of pressure, dew point, saturation pressure and pressure drop of asphaltenes, and on the basis of the pressure at the extremum of electromagnetic energy to determine the optimum pumping speed for faster execution pumping tests without the pressure drop in the sample below the value corresponding to the dew point pressure and/or saturation pressure.



 

Same patents:

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Sampler // 2257471

FIELD: oil-field equipment, particularly for obtaining fluid samples or testing fluids in boreholes or wells and may be used for integrated obtaining sample of multicomponent liquid-gas systems transported through pipelines.

SUBSTANCE: sampler comprises hollow body installed in high-pressure pipeline of wellhead fittings and extraction chamber with discharge channels. Rotary tool adapted for multicomponent liquid-gas medium flow regulation is installed inside the body. Sampler also has shutoff member with actuated sample extracting valve, handle and guiding tube. Sampler comprises hollow body made as a part of high-pressure pipeline and tool adapted for multicomponent liquid-gas medium flow regulation arranged in hollow body. The tool consists of flap installed on a shaft and having diameter corresponding to inner hollow body diameter, extraction chamber used to extract and mix multicomponent liquid-gas medium flow formed as annular cavity around hollow body. The cavity is divided into inlet and outlet parts by partition arranged at flap level. Inlet and outlet parts communicate with common multicomponent liquid-gas medium flow correspondingly through inlet and outlet channels on hollow body and through opening formed in the partition at sample extracting valve inlet. Drive screw installed in shutoff member body is connected with sample extracting valve so that drive screw and sample extracting valve may perform mutual rotation and move in axial direction. Sample extracting valve and shaft with flap mate each other so that they may perform synchronous limited rotation about common axis and mutual axial movement.

EFFECT: increased simplicity, provision of high-quality mixing of sample product and increased sample reliability.

3 dwg

Sampling device // 2258807

FIELD: oil field equipment, particularly for take samples from wellhead, namely for integrated sampling multi-component gas-liquid medium transported through pipelines.

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EFFECT: simplified structure and increased sampling quality.

2 dwg

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EFFECT: increased operational reliability and prevention of oil sample degassing due to improved air-tightness of sampling device interior.

2 cl, 1 dwg

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