WO2011073952A2

WO2011073952A2 - Method for extracting hydrocarbons

Info

Publication number: WO2011073952A2
Application number: PCT/IB2010/055906
Authority: WO
Inventors: Pierre Lemetayer; Félix NDINEMENU; Pascal Flourette; Benoît GIRARD
Original assignee: Total S.A.
Priority date: 2009-12-18
Filing date: 2010-12-17
Publication date: 2011-06-23
Also published as: FR2954398B1; CA2784427A1; CA2784427C; WO2011073952A3; FR2954398A1

Abstract

A method for extracting hydrocarbons from a reservoir by means of gas injection, including at least a lower well (112) comprising a horizontal portion (116) and a vertical portion (114) connecting the horizontal portion to the surface, at least one pipe (120) for extracting hydrocarbons and at least one gas injection pipe (130) opening into the extraction pipe, a plurality of temperature sensors (190) along the horizontal portion, at least one pressure sensor (200, 202) in the well, a gas injection valve (126) located on the surface on the injection pipe and controlling the gas injection rate, a gradually opening extraction choke (124) located on the surface on the extraction pipe, and an automaton (11) connected to the various sensors, to the choke located on the extraction pipe and to the gas injection valve. According to the invention, the extraction choke (124) and the gas injection valve (130) are controlled according to the difference between a temperature measured along the horizontal portion and the vaporisation temperature calculated according to a pressure measured along the horizontal portion.

Description

PROCESS FOR EXTRACTING HYDROCARBONS

The present invention relates to a process for extracting hydrocarbons from a reservoir and a hydrocarbon extraction plant.

The tank in question is likely to include viscous oils. Conventionally, using the definitions of the US Geological Survey, heavy oil is called an oil with a density below 22 ° API and a viscosity greater than 100cP. extra heavy oil (English extra heavy oil) an oil whose density is less than 10 ° API and the viscosity greater than 100cP, and is called bitumen (tar) an oil whose density is between 7 ° API and 12 ° API and whose viscosity is greater than 10 OOOcP.

The viscosity of an oil varies depending on the pressure and temperature to which it is subjected. Thus, the higher the temperature, the lower the viscosity of the oil. In situ viscosity is the viscosity of an oil at the pressure and temperature conditions encountered in the reservoir.

Only oils whose viscosity in situ is sufficiently low can be produced by "cold" pumping. These oils are called mobile oils. Beyond a certain viscosity, and especially for the viscosity values encountered for heavy oils, extra-heavy oils and bitumens, other processes must be implemented, such as thermal processes which consist in injecting the water vapor in the tank. The latent heat of the steam is transferred to the tank by condensation of the steam. The increase in temperature of the tank decreases the viscosity of the oil, and consequently facilitates its mobility in the tank.

Steam Assisted Gravity Drainage (SAGD) is a method of thermal recovery of low or non-moving oils based on the gravity drainage mechanism. Applicable for heavy oils, extra-heavy oils and for bitumens, the SAGD process uses a set of pairs of horizontal wells distributed relatively evenly in the tank. By pair of wells is meant a steam injector well drilled approximately 5m above a producing well. Each well is several hundred meters long, and each pair is typically spaced 100 to 150 meters from the next pair. Steam is injected continuously into the upper well (or injector well), developing a steam chamber around the injector well. Condensed oil and steam flow by gravity along the walls of the steam chamber to the lower well from where they are pumping out. For the extraction of bitumens, an initial phase of preheating of the tank by circulation of steam in the two wells is necessary to ensure communication between the two wells. The SAGD is described in particular in the patent application CA1130201.

The injection of steam makes it possible to reduce the viscosity of the hydrocarbons, in order to increase their mobility in order to favor their extraction. However, the pressure in the reservoir is not sufficient to allow the production of hydrocarbons, the wells can be activated by pumping means, such as PCP type volumetric pumps. A conventional alternative to pumping is to inject into the producing well a gas that causes the lightening of the oil column. Such a process is called in English "gas lift". This process is described for example in the patent application FR-A-2 672 936.

The specific application of gas lift to SAGD wells is described in SPE SPE / PS / CHOA 117489.

It is also known to automatically control SAGD wells activated by pumping rather than by "gas lift". The application FR 0901969 of 23 April 2009 describes the piloting of SAGD wells pumped, the speed of the pump being controlled as a function of the difference between the temperature measured at the inlet of the pump on the one hand, and the temperature of the pump. vaporization calculated according to the pressure measured at the inlet of the pump on the other hand.

The piloting of wells activated by gas lift poses particular problems, in particular the effect of "Steam Flashing". "Steam Flashing" is the vaporization of water by boiling under the effect of a drop in pressure.

Thus, in the producing well, the pressure decreasing sharply approaching the surface, the risk of steam flashing are high, especially when the fluid keeps a high temperature. However, the Steam Flashing in the upper part of the producing well can be beneficial because it contributes to the lightening of the fluid in the well. However, because steam flashing is a self-sustaining phenomenon, instabilities can be created that result in "plugged" production.

The vaporization of the water increases the gaseous phase and thus reduces the liquid content in the casing. In this case, or for other causes of instability, the pressure drop in the horizontal portion of the well may induce vapor penetration of the steam chamber directly from the upper well to the lower well. This phenomenon called "channeling" must be avoided: if the steam passes directly from the upper well to the lower well, the steam chamber will not develop homogeneously, which may result in a decrease in the recovery of steam. oil since some areas of the reservoir will no longer be drained. Channeling is a recurring problem for tanks operated in SAGD. The risk of steam flashing is a typical problem of wells activated by gas lift. For pump-activated wells, on the other hand, a pressure is imparted by the pump to the hydrocarbons in the extraction column. The pressure therefore increases substantially throughout the extraction column, which limits the risk of steam flashing. The risk of Steam Flashing is not specific to gas lift-activated wells: this problem can also be encountered in very deep wells. The risk of Steam Flashing is, however, amplified in wells activated by gas lift.

The mere vaporization of the water to saturate the gaseous phase caused by the drop in pressure, without reaching the saturation pressure, also increases the vapor phase, but less violently.

So even if the Steam Flashing and the simple vaporization can be favorable in the vertical part of the extraction column (because, like the gas injected for the gas lift, the vaporized water participates in the lightening of the column), it It is desirable to control them for tanks operated by gravity drainage, to avoid instabilities. In the particular case where there are two extraction columns, one at the heel and one at the toe of the horizontal part of the well, the control is even more complex.

Other mechanisms increase the instabilities on gas lift wells in SAGD: temperature variation in the drainage area or the flow of fluids entering the well.

There is therefore a need for a process for extracting hydrocarbons, particularly heavy oils, to stabilize the operation of these wells effectively.

For this purpose, the invention proposes a process for extracting hydrocarbons from a reservoir comprising

the provision of an installation comprising at least one well called a lower well comprising a substantially horizontal portion extending into the reservoir and a substantially vertical portion connecting the horizontal portion to the surface, the horizontal and vertical portions being connected by a heel, the well further comprising at least one hydrocarbon extraction casing and at least one gas injection casing opening into the extraction casing, a plurality of temperature sensors along the horizontal part, at least one sensor pressure in the well, a gas injection valve located on the surface of the injection casing and controlling the rate of gas injection, a progressive aperture extraction choke located on the surface of the extraction casing , an automaton connected to the different sensors, to the choke located on the extraction casing and to the gas injection valve,

the injection of gas by the gas injection casing into the extraction casing,

the extraction of hydrocarbons by the extraction casing, the control of the extraction choke and the gas injection valve as a function of the difference between a temperature measured along the horizontal part and the vaporization temperature calculated as a function of a pressure measured along the horizontal part.

According to a variant, the well further comprises

a second extraction casing and a second gas injection casing opening into the second extraction casing, the first extraction casing emerging at the heel and the second extraction casing opening at the end of the horizontal part; called a toe that is not connected to the vertical portion of the well, - a second gas injection valve located at the surface on the second injection casing and controlling the injection rate of gas into the second injection casing gas,

a second extraction aperture with progressive opening, situated on the surface on the second extraction casing,

the method further comprising

the injection of gas by the second gas injection tubing into the second extraction casing;

the extraction of hydrocarbons by the second extraction casing;

the control of the opening of the second extraction choke and of the second gas injection valve as a function of the difference between the temperature measured at a position along the horizontal part and the vaporization temperature calculated as a function of a measured pressure along the horizontal part.

According to one variant, the pressure selected is chosen from the group comprising - the pressure measured at the level of the heel,

if the installation comprises a pressure sensor at the heel and the toe, the pressure measured at the heel and the toe, the lowest pressure being used to determine the vaporization temperature,

- if the installation includes sensors along the horizontal part, the pressure measured along the horizontal part, the lowest pressure being used to determine the vaporisation temperature.

Alternatively, the temperature is the temperature at the heel or the highest temperature along the horizontal portion of the lower well.

According to a variant, the method furthermore comprises

the comparison of the difference of the temperatures with a setpoint value and, if the difference of the temperatures is greater than the setpoint value,

the opening of the first choke and, if appropriate, of the second choke, is increased, and the opening of the first valve and, if necessary, of the second valve is increased.

According to a variant, the opening of one or the other of the chokes and the opening of one or the other of the valves are preferred according to the position along the horizontal part of the lower well at which the temperature higher is measured.

According to one variant, the pressure corresponding to the set value of the temperature difference is converted into a bottom pressure setpoint applied to the heel of the lower well.

According to a variant, the method further comprises a step of calculating the speed of variation of the temperature difference for all the temperature sensors of the installation, and, if the speed of variation at a point of the horizontal part the lower well exceeds a predetermined threshold for a duration greater than a predetermined threshold, the opening of the first choke and valve and, where appropriate, the opening of the second choke and valve, are reduced.

According to a variant, the method furthermore comprises

comparing the temperature difference with a critical value, and if the difference between the temperature difference and the critical value is less than a predetermined threshold,

the opening of the first valve and, if appropriate, of the second valve, is reduced, and

- the opening of the first choke and, if necessary, of the second choke, is diminished.

According to a variant, the opening of one of the valves is preferred over the other of the valves, and the opening of one of the chokes is preferred over the other chokes.

According to a variant, the installation also comprises

an upper well comprising a substantially horizontal portion extending in the reservoir parallel to the horizontal portion of the lower well and a substantially vertical portion connecting the horizontal portion to the surface, the horizontal and vertical portions of the upper well being connected by a heel, the upper well further comprising one or two steam injection tubings in the reservoir, the method further comprising

- The reduction of steam injection into the casing of the upper well corresponding to the casing in the lower well for which is preferred the decrease in the opening of the valve and the choke.

The invention also relates to an installation for implementing the method as described above, comprising at least one well called a lower well comprising a substantially horizontal portion extending into the reservoir. and a substantially vertical portion connecting the horizontal portion to the surface, the horizontal and vertical portions being connected by a bead, the well further comprising at least one hydrocarbon extraction casing and at least one gas injection casing opening in the extraction casing, a plurality of temperature sensors along the horizontal portion, at least one pressure sensor in the well, a gas injection valve located on the surface of the injection casing and controlling the flow rate gas injection nozzle, a progressive opening extraction choke, located on the surface of the extraction casing, an automaton connected to the various sensors, to the choke located on the extraction casing and to the injection valve of gas, the automaton controlling the extraction choke and the gas injection valve as a function of the difference between a temperature measured along the horizontal part and the vaporization temperature calculated according to the n a pressure measured along the horizontal part.

According to a variant, the installation further comprises an upper well comprising a substantially horizontal portion extending in the reservoir parallel to the horizontal portion of the lower well and a substantially vertical portion connecting the horizontal portion to the surface, the horizontal and vertical portions. upper well being connected by a heel, the upper well further comprising one or two steam injection casings in the reservoir.

Other features and advantages of the invention will appear on reading the following detailed description of the embodiments of the invention, given by way of example only and with reference to the drawings which show:

Figure 1 is a schematic view of an installation according to the invention;

Figure 2 is a schematic view of a lower well according to another example as that of Figure 1;

Figure 3, a graph relating to the saturation of water.

The invention relates to a process for extracting hydrocarbons from a reservoir using an installation comprising a lower well (or producing well). The lower well comprises a substantially horizontal portion extending into the reservoir and a substantially vertical portion connecting the horizontal portion to the surface, the horizontal and vertical portions being connected by a heel. The lower well further comprises at least one hydrocarbon extraction casing and at least one gas injection casing opening into the extraction casing. A gas injection valve is located on the surface of the injection casing and controls the rate of gas injection. A progressive aperture extraction choke is located on the surface of the extraction casing. The method includes controlling the opening of the extraction choke and the gas injection valve as a function of the difference between a temperature measured along the portion horizontal and the vaporization temperature calculated according to a measured pressure along the horizontal part.

This makes it possible to maintain a maximum withdrawal of hydrocarbons, that is to say, keep the extraction choke located on the extraction tube open to the maximum and have an optimum gas flow, while avoiding the problems of Steam Flashing and Channeling. This makes it possible to stabilize the operation of these wells effectively.

For this, and as will be described later, the temperature difference value can be kept as low as possible. However, a decrease in the temperature difference value induces risks of Steam Flashing and Channeling. It is therefore desirable to control the opening of the production choke and the gas injection valve as a function of the calculated temperature difference values.

FIG. 1 shows a reservoir 10 with two wells 12, 112. The first well 12 is a steam injection well and the second well 112 is a hydrocarbon producing well. The producing well 112 is located lower in the reservoir than the injector well 12. The wells 12 and 112 are for example distant from about 5 to 8 meters.

The underground reservoir contains low or non-mobile hydrocarbons, such as heavy oils, extra-heavy oils or bitumens. Each well has two ends, an upper end located on the surface and a lower end located in the tank. The well further comprises two distinct parts, namely a portion 14, 1 14 vertical or slightly inclined relative to the vertical, connected to the upper end of the well and a portion 16, 116 substantially horizontal and connected to the lower end of Wells. A junction or heel 48, 148 (for "heel" in English) allows the connection of substantially vertical portions 14, 114 to substantially horizontal portions 16, 116. The portion of the well 14, 114 substantially vertical is coated with a continuous casing. Part 16, 116 substantially horizontal is coated with a discontinuous casing, that is to say having perforations authorizing, for the injector well 12, the passage of steam from the injector well to the reservoir and the well producing the passage of hydrocarbon reservoir to the interior of the producing well 112. One can also consider a well having a different architecture, with a single portion 16, 116 substantially horizontal when the terrain is sloping.

The well 12 may comprise a single steam injection tubing. The well 12 may also comprise two casings: a first injection casing 18 and a second injection casing 20. The casing geometry may vary. According to the example of Figure 1, the two casings are parallel to each other. The first casing 18 extends from the upper end of the injector well 12 to the lower end of the injector well 12, also called toe 50 (or "toe" in English). The second casing 20 extends from the upper end of the injector well 12 to the vicinity of the heel connecting the parts 14 and 16. The first casing 18 is therefore longer than the second casing 20. Steam can be injected into the casing. the two injection casings 18, 20. Due to the difference in length of the casings 18 and 20, the steam is injected both at the heel 48 and the toe 50 of the injector well 12 towards the reservoir, which ensures a good distribution of the vapor in the zone of the reservoir located near the horizontal part of the injection well 12.

Another architecture of upper well 12 is conceivable according to which the injection casings 18, 20 are concentric. For example, the casing 18, whose end is at the lower end of the injection well 12 is located in the casing 20. The casing 18 thus extends beyond the casing 20.

In another well architecture, the injection well 12 comprises only one casing 18, the lower end of which is two-thirds of the distance separating the bead from the lower end of the well 12. Punctures are provided in the casing 18 between the heel and the lower end of the casing 18, so as to allow the injection of steam into the reservoir and the development of the steam chamber.

The casings 18, 20 of the injector well 12 are equipped with jets 22, 24 which allow the control of the steam injection rate. Thus, the choke 22 allows the control of the injection rate in the casing 18, and the choke 24 allows the control of the injection rate in the casing 20. The chokes 22 and 24 are adjustable opening, which allows to adjust precisely the flow in the casings 18, 20. The adjustable opening of the chokes allows a continuous control of the chokes. Thus, rather than opening the stops step by step, sequentially, the chokes are continuously controlled opening or closing depending on the reaction of the well.

FIG. 1 shows an example of a producing well 112. The producing well 112 comprises at least a first casing 120, preferably also a second casing 122, by means of which the hydrocarbons extracted from the reservoir are raised towards the surface. The upper end of the extraction casings 120, 122 is located on the surface. The lower end of the extraction casing 120 is located at the heel 148 or further in the lower well, such as for example midway between the heel 148 and the lower end 150 of the producing well. The lower end of the extraction casing 122 is located at the toe 150 of the producing well. Perforations may be provided along the extraction casings 120, 122 with a diversion system, to control the distribution of the racking along the drain. The lower end of the extraction casings 120, 122 is immersed in the hydrocarbons from the reservoir and having entered the producing well 112 throughout the substantially horizontal portion 116.

A first choke 124 and a second choke 125 are respectively located on the casing 120 and on the casing 122, at the upper end of the well to control the flow of hydrocarbons, in particular to avoid the appearance of plugs at the level of the installations. area.

The producing well 112 further comprises first and second gas injection casings 130, 132 respectively in the casings 120 and 122. The injection casings 130, 132 open into the extraction casings 120, 122 at the level of the heel 148. According to FIG. 1, the injection casings 130, 132 are inside the extraction casings 120, 122. The extraction casings 120, 122 form an annular space around the injection casings 130, 132 When the pressure in the gas injection casings 130, 132 exceeds that of the hydrocarbons in the extraction casings 120, 122, the gas penetrates according to the arrows 152, 154 into the extraction casings 120, 122 and displaces the casings. hydrocarbons to the head of the producing well 112.

A valve 126 and a valve 127 are located respectively on the injection tubing 130 and the injection tubing 132 at the upper end of the well to control the gas injection rate.

The installation further comprises at least one temperature sensor 190 at the heel 148. Preferably, temperature information is provided along the producing well 112 in its horizontal portion 116. The temperature information can be provided. by a plurality of sensors or by an optical fiber 190 DTS ("Distributed Temperature Sensing" in English).

At least one pressure sensor 200 is located at the heel 148. The sensor 200 is preferably in the form of a bubble, intended to measure the pressure at the heel 148. It is also possible to provide another sensor The advantage of the two sensors 200, 202 is to be able to better modulate the extraction by the two casings 120, 122. Each extraction casing 120, 122 may be provided with a pressure sensor 204, 206 at the surface.

The installation is provided with a controller 11 for controlling and controlling the operation of the installation. In particular, the controller 11 is connected to the various elements of the installation. For example, the controller 11 can send signals to the chokes and valves and receive signals from the sensors. For the sake of clarity, the link between the PLC and the different elements of FIG. schematically by an arrow 13. The controller 11 is able to act on the opening and closing of the chokes and valves.

FIG. 2 shows another example of producing well 112, which is an alternative to the producing well of FIG. 1. According to FIG. 2, the extraction casings 120, 122 are concentric. The casing 122, whose end is at the end 150 of the injection well 112 is located in the casing 120. The casing 122 thus extends beyond the casing 120. The injection casing 130 forms an annular space around the extraction casing 120. The gas is injected from the injection casing 130 to the extraction casing 120 according to the arrows 156. The injection casing 132 is held inside the casing of the casing 120. extraction 122 and the gas is injected according to the arrow 154. A temperature sensor system 190, in the form of a sensor chain or an optical fiber, can be positioned along the extraction casing 122.

The hydrocarbon extraction process will now be presented. The extraction process takes place once a vapor chamber 26 has developed in the tank, as explained for example in the application FR 08 07 374 of December 22, 2008 filed by the applicant of the present application. Once the viscosity of the hydrocarbons has sufficiently decreased so that the oil becomes mobile and flows into the lower well 112, the injection of steam is stopped in the well 112. The well 112 becomes a producing well, allowing the extraction of the hydrocarbons from the reservoir to the surface through the casing 120 and the casing 122 where appropriate. The method can be implemented by the automaton. It applies with a minimum configuration of the lower well 112 having an injection casing 130 and an extraction casing 120.

The method comprises injecting gas through the injection casing (s) 130, 132 into the extraction casing (s) 120, 122. This makes it possible to lighten the hydrocarbons and to drive them towards the surface with a view to their extraction. . The extraction nozzle (s) 124, 125 and the injection valve (s) 126, 127 are controlled as a function of the difference between, on the one hand, a temperature measured along the horizontal portion 116 of the well 112 and on the other hand A vaporization temperature calculated as a function of a pressure measured along the horizontal portion 116. This temperature difference is subsequently called subcool.

If the installation comprises only a pressure sensor, for example the sensor 200 located at the heel, the pressure can be measured at the heel. The vaporization temperature is calculated according to this heel pressure. The temperature selected may be the temperature measured at the bead or, preferably, the highest temperature measured along the horizontal portion of the well 112. Thus, the extraction choke (s) 124, 125 and the valve (s) injection 126, 127 are controlled according to the difference between the highest temperature along the part horizontal 1 16 well 1 12 and the vaporization temperature calculated according to the pressure at the heel.

This allows to calculate the minimum subcool, which best protects the installation against the effects of steam flashing and channeling. The method further allows the distance between the bead and the position at which the highest temperature is measured to be determined.

If the installation comprises two pressure sensors, one being located for example at the heel and the other being located for example at the toe, the pressure can be not only measured at the heel but also at the toe. We will then retain the lowest pressure between the two pressures. The extraction nozzle (s) 124, 125 and the injection valve (s) 126, 127 are then controlled according to the difference between the highest temperature along the horizontal portion 116 of the well 112 and the vaporization temperature. calculated based on the lowest pressure between heel pressure and toe pressure. This makes it possible to calculate an even lower subcool value and to increase the security of the installation. Indeed, the vaporization temperature varying in the same way as the pressure, taking into account the lowest pressure between the pressure at the heel and the pressure at the toe allows to determine the lowest vaporization temperature in the horizontal part of the well. The difference between this lowest vaporization temperature and the highest temperature along the horizontal part thus makes it possible to calculate an even lower subcool value.

It is also conceivable that the installation makes it possible to determine the pressure along the horizontal portion of the well 112. The lower pressure will then be retained along the horizontal portion of the well 1 12. The extraction choke or chucks 124, 125 and the injection valve (s) 126, 127 are then controlled as a function of the difference between the highest temperature along the horizontal portion 116 of the well 112 and the vaporization temperature calculated as a function of the pressure. lower along the horizontal portion of the well 112. As explained above, this allows to calculate an even lower subcool value and further increase the safety of the installation.

The method also includes comparing the calculated subcool value to a set subcool value. If the calculated subcool value is greater than the set point value, the withdrawal is increased on the first extraction pipe 120 and, if appropriate, on the second extraction pipe 122. The withdrawal on one or the other other casings 120, 122 may be preferred depending on the position at which the highest temperature is measured. For this, the chokes and the valves are controlled to increase the hydrocarbon extraction rate and the gas injection rate. At constant temperature, increase racking tends to reduce the pressure, which decreases the vaporization temperature, and therefore decreases the subcooling. Thus, if the position at which the temperature is higher is closer to the heel, it favors racking at the heel, and vice versa.

This is shown in Figure 3. Curve 160 is the saturation curve of water. Point A is the current operating point. The temperature of the point A is that corresponding to the temperature at the bead, or, preferably, at the highest temperature along the horizontal portion of the well 112. The point B corresponds to the vaporization temperature for the pressure measured (at heel, toe or between these two positions). The difference between the temperature at point A and the temperature at point B corresponds to the calculated subcool 162 described above. Segment 164 between points C and D corresponds to the setpoint subcool. The withdrawal in the extraction casings is adjusted to reach this setpoint subcool value.

Preferably, the automaton converts the setpoint subcool into a bottom pressure setpoint, applied at the heel of well 112. In FIG. 3, the setpoint subcool can be reached by decreasing the pressure (at which the subcool has has been determined) up to a background pressure setpoint. The difference between the reference pressure at the bottom of the well and the measured pressure is converted into the head pressure and injected flow rate for each casing and injected flow rate. The position of the maximum temperature point can be taken into account.

To better anticipate the development of the channeling effect, the method comprises a step of calculating the rate of variation as a function of time of the subcool, for all the available temperature sensors or a series of points in case of continuous measurement. using a DTS optical fiber. The controller 11 determines the maximum speed and the position of the sensor which observes this variation. If the maximum speed observed is greater than a predetermined threshold and for a duration greater than a predetermined threshold, the controller triggers an alert procedure. A preferred mode is the reduction of the withdrawal on the two casings 120, 122. For this, the chokes and the valves are controlled to reduce the flow of hydrocarbon extraction and the gas injection rate (decrease of the opening chokes and valves). The decrease of the withdrawal makes it possible to increase the pressure in the well 112 and thus to increase the subcool.

Permanently, the subcool is maintained at a value greater than a critical value, lower than the set subcool value. This allows to maintain a minimal value of subcool: a decrease in the value of the subcool entails a significant risk of developing the effects of team flashing and channeling. A weak subcool indicates that, at the measured pressure, the temperature approaches the vaporization temperature. If the gap between the subcool and the critical value is below a predetermined threshold, the withdrawal is decreased as indicated above, which tends to increase the subcool again.

If the actions to guarantee a minimum subcooling value are not sufficient, it is also conceivable to reduce the injection of steam into the upper well 12. The reduction of the steam in the injection casing 18 or 20 will be preferred according to the invention. casing of the lower well 112 for which it has been realized as a priority the reduction of the withdrawal. Indeed, decrease the injection of steam by the upper well 12 reduces the temperature in the lower well 112. This allows to increase the subcool.

The PLC also ensures that certain operating parameters of the system comply with limit values. The parameters are at least one of the following parameters:

a minimum and maximum flow rate of gas injection into the lower well 112;

- a minimum pressure value at the wellhead, at the extraction casings;

- a minimum and maximum steam injection rate in the upper well vapor injection casings, if applicable.

Claims

1. A process for extracting hydrocarbons from a reservoir comprising

- the supply of an installation comprising

at least one well (112) called a lower well comprising a portion

substantially horizontal (116) extending into the reservoir and a portion

substantially vertical (114) connecting the horizontal portion to the surface, the horizontal and vertical portions being connected by a heel (148), the well further comprising at least one hydrocarbon extraction casing (120) and at least one casing injecting (130) gas opening into the extraction casing,

a plurality of temperature sensors (190) along the horizontal portion, at least one pressure sensor (200, 202) in the well,

a gas injection valve (126) located on the surface of the injection casing and controlling the gas injection flow rate,

an extraction chute (124) with progressive opening, located on the surface of the extraction casing,

an automaton (11) connected to the various sensors, to the choke located on the extraction casing and to the gas injection valve,

the injection of gas through the injection tubing (130) of gas into the extraction casing (120),

the extraction of hydrocarbons by the extraction casing (120),

controlling the extraction choke (124) and the gas injection valve (130) as a function of the difference between a temperature measured along the horizontal portion and the vaporization temperature calculated as a function of a pressure measured along the horizontal part.

2. The process according to claim 1, the well further comprising

a second extraction casing (122) and a second gas injection casing (132) opening into the second extraction casing, the first extraction casing opening at the heel and the second extraction casing opening into the casing; end of the horizontal part called toe which is not connected to the vertical part of the well,

a second gas injection valve (127) located on the surface of the second injection casing and controlling the rate of gas injection into the second gas injection casing,

a second extraction aperture (125) with progressive opening, situated on the surface on the second extraction casing, the method further comprising

the extraction of hydrocarbons by the second extraction casing;

3. The method according to one of claims 1 or 2, wherein the selected pressure is selected from the group comprising

the pressure measured at the heel (148),

if the installation comprises a pressure sensor at the heel (148) and the toe (150), the pressure measured at the heel and the toe, the lowest pressure being used to determine the vaporization temperature. ,

- if the installation includes sensors along the horizontal part (116), the pressure measured along the horizontal part, the lowest pressure being used to determine the vaporization temperature.

4. The method according to one of the preceding claims, wherein the

temperature is the temperature at the heel (148) or the highest temperature along the horizontal portion (116) of the lower well (112).

5. The method according to one of the preceding claims, further comprising

the opening of the first choke (124) and, if appropriate, of the second choke (125) is increased, and

the opening of the first valve (126) and, if appropriate, the second valve (127) is increased.

6. The method of claim 5, wherein the opening of one or the other of the chokes (124, 125) and the opening of one or the other of the valves (126, 127) are preferred depending on the position along the horizontal portion of the lower well at which the highest temperature is measured.

7. The method according to one of claims 5 or 6, wherein the pressure corresponding to the set value of the temperature difference is converted into a bottom pressure set point applied to the lower well heel (112).

8. The method according to one of the preceding claims, further comprising a step of calculating the speed of variation of the temperature difference for all of the temperature sensors (190) of the installation, and, if the speed of variation at a point of the horizontal portion (116) of the lower well (112) exceeds a predetermined threshold for a duration greater than a predetermined threshold, the opening of the first chokes (124) and valve (126) and, if appropriate the opening of the second chokes (125) and the valve (127) are reduced.

The method according to one of the preceding claims, further comprising

the opening of the first valve (126) and, if appropriate, of the second valve (127) is reduced, and

- The opening of the first choke (124) and, where appropriate, the second choke (125), is decreased.

10. The method according to the preceding claim, wherein the opening of one of the valves is preferred over the other valves, and the opening of one of the chokes is preferred over the other chokes .

11. The method of claim 10, the installation further comprising

- an upper well (12) comprising a substantially horizontal portion (16) extending in the reservoir parallel to the horizontal portion of the lower well and a substantially vertical portion (14) connecting the horizontal portion to the surface, the horizontal and vertical portions the upper well being connected by a heel (48), the upper well further comprising one or two casings (18, 20) for injecting steam into the reservoir,

the method further comprising

12. An installation for implementing the method according to one of the preceding claims, comprising

at least one well (112) called a lower well comprising a portion

substantially horizontal (116) extending into the reservoir and a portion

an automaton (11) connected to the various sensors, to the choke located on the extraction casing and to the gas injection valve, the automaton controlling the extraction choke (124) and the injection valve ( 130) as a function of the difference between a temperature measured along the horizontal portion and the vaporization temperature calculated as a function of a pressure measured along the horizontal portion.

The installation of claim 12, further comprising an upper well (12) comprising a substantially horizontal portion (16) extending into the reservoir parallel to the horizontal portion of the lower well and a substantially vertical portion (14) connecting the horizontal portion at the surface, the horizontal and vertical portions of the upper well being connected by a heel (48), the upper well further comprising one or two casings (18, 20) for injecting steam into the reservoir.