RU2727966C1 - Method for determination of liquid level in well - Google Patents

Abstract

FIELD: oil and gas industry.SUBSTANCE: invention relates to oil industry, in particular to evaluation of liquid level in oil wells, and can be used for determination of dynamic level of well fluid. Method includes scheduled poll of temperature sensors system arranged along well shaft, on the basis of which data thermogram of annular liquid condition is formed and temperature gradient is calculated in each measured point, wherein point with maximum value of gradient will be interface of liquid-gas phase media and correspond to level of dynamic fluid. At that, local and/or distributed sources of annular fluid temperature change are located in annular space of the well, which form static zones of heating and/or cooling, and point with maximum value of gradient is fixed either during heating or return to initial geotherm, or during cooling or return to initial geotherm, or during simultaneous heating and cooling, and return to initial geotherm.EFFECT: design of a method for measuring high-precision level of dynamic fluid in low- and medium-temperature wells.4 cl, 10 dwg

Description

The invention relates to the field of the oil industry, in particular to assessing the liquid level in oil wells and can be used to determine the dynamic level of the well fluid.

Determining the fluid level in a well is a fairly common task. For oil and water wells, this information is used to determine the bottomhole pressure, as well as to estimate the liquid level above the installation of an electric driven centrifugal pump (ESP) to prevent air from entering the pump intake. For gas producing wells, determining the liquid level allows you to track the accumulation of fluid at the bottom and take timely action to prevent shutdown of the gas producing well.

This problem is especially important for low-rate gas wells. During the operation of gas wells, in addition to gas, there is a liquid phase in the formation fluid flow (including water and condensate). In the process of gas lifting through the tubing (tubing), the liquid phase (water and condensate) can, in the event of insufficient flow rates, begin to move downward under the action of gravitational forces and accumulate at the bottom of the well. In case of overlap of the perforation intervals, the production well will stop. To return it to production, special measures will be required at the well related to the removal of liquid from the well bottom and the resumption of gas flow.

This issue becomes very important in connection with the gradual transition of the main stock of gas production wells from high-rate Cenomanian wells towards gas reservoirs with low permeability and gas shale deposits. Such fields are developed using multistage hydraulic fracturing (hydraulic fracturing) technology. Such wells are characterized by a significant decrease in gas production rate up to 70% during the first year of well operation.

Thus, monitoring the liquid level above the bottom of oil and gas producing wells is one of the most important tasks in well operation. To measure the liquid level using the proposed method, the well equipment must meet the following requirements:

• ability to determine the level in multi-component systems (including pricing);

• high resolution of measurements;

• no need to use additional funds, relatively low labor intensity of preparation and implementation of research;

• continuity of research, including during well shut-in.

A known method for measuring the level according to the method described in patent RU 2247835, MKI: E21B 47/04, 2005 The invention relates to the field of research and control of wells and can be used to measure the dynamic level of a liquid prone to foaming. In the method, the liquid level is determined by measuring the transit time of a sound pulse from the wellhead to the liquid level with preliminary foam destruction. To do this, a calculated amount of a reagent for destroying the foam is sprayed into the annulus with the possibility of maximum contact with the foam, then the spraying is stopped. The time of passage of the sound pulse from the wellhead to the liquid level is determined not earlier than 15 minutes after the cessation of spraying. Spraying is carried out under a pressure exceeding the gas pressure in the annular space. An antifoam agent for drilling fluids "Trixan" can be used as a reagent for breaking foam.

Among the disadvantages of the above method, it is worth noting that the technology requires the use of additional means to eliminate foaming, which causes additional manipulations that significantly complicate the process.

The known method described in (see Bormashov V.P. Clarification of the dynamic level of annular fluid in mechanized wells using a deep thermogram // Oil industry. - 2007. - No. 7. - P. 124-128), which involves the placement of temperature sensors along the wellbore at a distance of at least 20-40 m from each other with subsequent interrogation. After polling all temperature sensors, a thermogram is formed, according to which the temperature gradient at each point is calculated. The point with the maximum gradient value will be the interface between the media. When comparing the data of determining the liquid level by the temperature gradient and the data of annular density measurement, it was revealed that the method has a resolution of no more than 10 m.

Accordingly, in this method, the disadvantages are the resolution of the measurements, as well as the need to accommodate a large number of sensors, which causes laborious operation.

From a similar subject matter of the patented method, it is known about the use of fiber-optic logging cables in oil-producing wells to collect data on well parameters (RU 2445656 MKI: G02B 6/44, 2012). The disadvantage is that, among other downhole measurements, this method is not capable of measuring the liquid level.

From a technological point of view, the closest patent is a method for determining the liquid level in an oil well with a high temperature producing super-viscous oil (RU 2494248 MKI: E21B 47/047, 2013), taken as a prototype. In this method, a fiber optic cable is lowered into a production casing and measures the temperature along the wellbore. In the course of measurements, a graph of temperature versus depth is plotted. The graph shows a temperature jump of at least 10 degrees, from the side of the wellhead, which will determine the depth of the interface between the gas and liquid phases. All other jumps deep into the well are not taken into account. The reliability of the method is confirmed by comparative data on the wavemeter.

Determination of the dynamic liquid level described in the prototype does not imply the use of additional means in addition to a distributed temperature sensor, since the fluid temperature is sufficient to clearly determine the liquid level along the temperature gradient at the interface. Heat losses to the surrounding space are minimal, since during such operation, the area treated with steam from the adjacent well and the temperature of the fluid warm up the surrounding space. For other wells, it is necessary to artificially create a temperature difference.

The disadvantage of this method is that it does not allow measuring the dynamic level of the liquid in low and medium temperature wells, although for high temperature wells its accuracy does not exceed 10 m.

The technical result of the proposed method for determining the dynamic fluid level in the well is to eliminate the disadvantages of the known technical solution (prototype), namely, to create a method capable of measuring the high-precision level of dynamic fluid in low- and medium-temperature wells.

The technical result in the method for determining the dynamic level of the annular fluid in mechanized wells using a deep thermogram, including periodic polling of temperature sensors located along the wellbore, on the basis of which a thermogram of the annular fluid state is formed and the temperature gradient is calculated at each measured point, while point c the maximum value of the gradient will be the interface between the liquid-gas phase media and correspond to the level of the dynamic fluid, achieved by the fact that local and / or distributed sources of change in the temperature of the annular fluid are placed in the annulus of the well, which form static zones of heating and / or cooling, and the point with the maximum value of the gradient is recorded either in the process of heating or returning to the initial geotherm, or in the process of cooling or returning to the initial geotherm, or in the process of simultaneous heating and cooling, and returning to the initial geotherm rme.

Placement in the annulus of the well of local sources of changes in the temperature of the annular fluid, which form static heating and / or cooling zones, makes it possible to increase the temperature contrast for those wells whose temperature and fluid temperature are insufficient to determine the level of the dynamic fluid.

The point with the maximum value of the gradient is fixed either during heating, for a faster result, but requiring more power from the heating source, or return to the initial geotherm, which allows, without spending a significant amount of energy, to obtain the result over a longer period of time.

The point with the maximum value of the gradient is fixed either during the cooling process, for a faster result, but requiring more power from the cooling source, or return to the initial geotherm, which allows obtaining the result over a longer period of time without spending a significant amount of energy.

The fixation of the point with the maximum value of the gradient is carried out in the process of creating an additional temperature difference by means of simultaneous heating and cooling, for a faster result, but requiring more power heating and cooling source, or returning to the initial geotherm, which allows you to obtain a result without spending a significant amount of energy. longer period of time.

It is advantageous to use a heating cable or capillary tube with circulating hot fluid as a local and / or distributed source of temperature rise.

It is advisable to use a capillary tube with circulating cold fluid as a local and / or distributed source of temperature reduction.

It is promising to use simultaneous heating and cooling to increase the contrast, which is carried out by creating heated local zones or a constant zone along the wellbore and creating a cooled local zone at the interface, or by creating a cooled constant zone along the wellbore and creating a heated local zone at the interface.

The use of heating and / or cooling pulses in the method allows to provide a pronounced temperature gradient and, accordingly, guarantees a clear definition of the liquid-gas interface, in all operating conditions, even in the presence of foaming in the annulus of the well, which is not known among analogs of the proposed method, but hence, it meets the criterion "inventive step".

The essence of the proposed method is illustrated by the ones presented in FIG. 1-10.

FIG. 1 shows a figure explaining well heating with a distributed heating element (heating cable or capillary tube with hot circulating fluid), where: 1 - tubing (tubing), 2 - production casing, 3 - distributed temperature logging system, 4 - dynamic level liquids, 5 - a distributed heating cable (the heating cable can be divided into sections that are not conventionally shown in the figure) or a capillary tube with circulating hot fluid.

FIG. 2 shows a figure explaining the heating of the well with a local heating element (chemical reagent), where: 6 - tubing (tubing), 7 - production casing, 8 - distributed thermometry system, 9 - dynamic fluid level, 10 - heating chemical ...

FIG. 3 shows a schematic graph of data obtained from a distributed thermometry system with heating elements, explaining the schematic determination of the dynamic fluid level in the well, where: 11 - gaseous medium in the annulus of the well, 12 - maximum thermal gradient that determines the level of dynamic fluid, 13 - fluid medium in the annulus of the well.

FIG. 4 shows a figure explaining the cooling of a well with a distributed cooling element (capillary tube with circulating fluid), where: 14 - tubing (tubing), 15 - production casing, 16 - distributed temperature logging system, 17 - dynamic fluid level, 18 - capillary tube with circulating cold fluid.

FIG. 5 shows a figure explaining the cooling of the well with a local cooling element (chemical reagent), where: 19 - tubing (tubing), 20 - production casing, 21 - distributed thermometry system, 22 - dynamic liquid level, 23 - coolant chemical ...

FIG. 6 shows a schematic graph of data obtained from a distributed thermometry system with cooling elements, explaining the schematic determination of the dynamic fluid level in the well, where: 24 is the gaseous medium in the annulus of the well, 25 is the maximum thermal gradient that determines the level of the dynamic fluid, 26 is the fluid medium in the annulus of the well.

FIG. 7 shows a figure explaining the simultaneous heating and cooling of a well with a distributed heating element (heating cable or capillary tube with circulating hot fluid) and a local cooling element (chemical reagent), where: 27 - tubing (tubing), 28 - production casing , 29 - distributed thermometry system, 30 - dynamic liquid level, 31 - distributed heating cable (divided into sections heating cable, not shown in the figure) or capillary tube with circulating hot fluid, 32 - cooling chemical reagent.

FIG. 8 shows a schematic graph of data obtained from a distributed temperature logging system with simultaneous distributed heating and local cooling at the interface, explaining the schematic determination of the dynamic fluid level in the well, where: 33 is the gaseous medium in the annulus of the well, 34 is the maximum thermal gradient that determines dynamic fluid level, 35 - fluid medium in the annulus of the well.

FIG. 9 shows a figure explaining the simultaneous cooling and heating of the well with a distributed cooling element (capillary tube with circulating fluid) and a local heating element (chemical reagent), where: 36 - tubing (tubing), 37 - production casing, 38 - distributed thermometry system, 39 - dynamic liquid level, 40 - distributed heating cable (divided into sections heating cable, not shown in the figure) or capillary tube with circulating hot fluid, 41 - capillary tube with circulating cold fluid.

FIG. 10 shows a schematic graph of data obtained from a distributed thermometry system with simultaneous distributed cooling and local heating with chemical reagents at the interface, explaining the schematic determination of the dynamic fluid level in the well, where: 42 is the gaseous medium in the annulus of the well, 43 is the maximum thermal gradient determining the level of dynamic fluid, 44 - fluid medium in the annulus of the well.

We will consider the implementation of the proposed method using FIG. 1-10.

Options 1 and 2. Collecting temperature data from wells with the assembly shown in FIG. 1, 2 is carried out as follows. Before starting measurements, the power supply for the heating cable (5) is turned on and kept for a time interval sufficient to increase the temperature in the heating zone to values sufficient to create a thermal gradient, or the heating chemical is lowered to the interface between the two media (10). The distributed thermometry system (3, 8) records the temperature values and a thermogram is formed, shown in the graph in Fig. 3. After that, on the obtained thermogram, the maximum thermal gradient (12) corresponding to the interface between the liquid (13) and gas (11) phases is determined, which determines the dynamic level of the liquid in the annulus of the well.

Options 3 and 4. Collecting temperature data from wells with the assembly shown in FIG. 4, 5 is carried out as follows. Before starting the measurements, turn on the power source to supply the circulating cold fluid to the capillary tube (18) and keep it in a time interval sufficient to lower the temperature in the cooling zone to values sufficient to create a thermal gradient, or lower the cooling chemical reagent to the interface between the two media (23 ). The distributed thermometry system (16, 21) records the temperature values and a thermogram is formed, shown in the graph in Fig. 6. After that, the obtained thermogram determines the maximum thermal gradient (25) corresponding to the interface between the liquid (26) and gas (24) phases, which determines the dynamic level of the liquid in the annulus of the well.

Option 5. In cases where the thermal gradient created by the heating methods described above (options 1 and 2) is not enough, it is possible to increase the temperature gradient using a cooling chemical. Collecting temperature data from wells with the arrangement shown in FIG. 7 is carried out as follows. Before starting the measurements, the power supply for the heating cable (31) is turned on and kept for a time interval sufficient to increase the temperature in the heating zone to values sufficient to create a thermal gradient; at the same time, a cooling chemical reagent (32) is lowered to the interface. The distributed thermometry system (29) records the temperature values and a thermogram is formed, shown in the graph in Fig. 8. After that, the obtained thermogram determines the maximum thermal gradient (34) corresponding to the interface between the liquid (35) and gas (33) phases, which determines the dynamic liquid level in the annulus of the well.

Option 6. In cases where the thermal gradient created by the cooling methods described above (options 3 and 4) is not enough, it is possible to increase the temperature gradient using a heating chemical. Collecting temperature data from wells with the arrangement shown in FIG. 9 is carried out as follows. Before starting the measurements, turn on the power source to supply the circulating cold fluid to the capillary tube (40) and hold it in a time interval sufficient to lower the temperature in the cooling zone to values sufficient to create a thermal gradient; at the same time, a heating chemical is lowered to the interface (41). The distributed thermometry system (38) records the temperature values and a thermogram is formed, shown in the graph of FIG. 10. After that, the obtained thermogram determines the maximum thermal gradient (43) corresponding to the interface between the liquid (44) and gas (42) phases, which determines the dynamic liquid level in the annulus of the well.

Thus, the claimed method makes it possible to determine the dynamic fluid level in wells under various operating conditions, artificially creating a thermal gradient by distributed and local sources of temperature changes, as a result of which a maximum thermal gradient is created at the level of the separation of two media.

Claims (4)

1. A method for determining the dynamic level of the annular fluid in mechanized wells using a deep thermogram, including periodic polling of temperature sensors located along the wellbore, on the basis of which a thermogram of the annular fluid state is formed and the temperature gradient at each measured point is calculated, while the point with the maximum the value of the gradient will be the interface between the liquid-gas phase media and correspond to the level of the dynamic fluid, characterized in that local and / or distributed sources of changes in the temperature of the annular fluid are placed in the annulus of the well, which form static zones of heating and / or cooling, and point c the maximum value of the gradient is fixed either during heating or returning to the initial geotherm, or during cooling or returning to the initial geotherm, or during simultaneous heating and cooling and returning to the initial geotherm. 2. A method according to claim 1, characterized in that a heating cable or a capillary tube with circulating hot fluid is used as a local and / or distributed source of temperature rise. 3. The method according to claim 1, characterized in that a capillary tube with circulating cold fluid is used as a local and / or distributed source of temperature lowering. 4. The method according to claim 1, characterized in that simultaneous heating and cooling are performed by creating heated local zones or a constant zone along the wellbore and creating a cooled local zone at the interface, or creating a cooled constant zone along the wellbore and creating a heated local zone at the interface.

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