WO2015052404A2

WO2015052404A2 - Fluid discharge device

Info

Publication number: WO2015052404A2
Application number: PCT/FR2014/052425
Authority: WO
Inventors: Pierre Valette; Pierre Lemetayer; Patrick Lamy; Philippe RENOUF
Original assignee: Total Sa
Priority date: 2013-10-09
Filing date: 2014-09-26
Publication date: 2015-04-16
Also published as: WO2015052404A3; FR3011574B1; FR3011574A1

Abstract

The present invention relates to a fluid discharge device able to be positioned in a hydrocarbon production well. The device comprises a discharge tube, one end of said tube being able to be connected to a pump positioned in the hydrocarbon production well for pumping at least one liquid; an insulator in contact with the tube and able to limit a flow of fluid between a wall of the tube and a wall of the well, from a first space formed between the insulator and the well bottom toward a second space formed between the insulator and the well head; an opening formed on an opening side on said tube able to allow a gas to flow from said first space into said tube; and a non-return valve mounted on said opening, the valve being able to block a fluid present in said tube from flowing toward the first space.

Description

FLUID EVACUATION DEVICE

The present invention relates to the field of oil exploitation and in particular the field of the production of hydrocarbons assisted by a pump installed in a well.

During the operation of an assisted well, the natural production of liquid hydrocarbons may be insufficient to allow an economically profitable exploitation of the well. In some situations, production may even be zero.

Many methods exist to improve the production of these hydrocarbon wells such as the injection of gas into the riser in order to lighten it (technique called "gas lift" in English).

It is also possible to install pumps (either on the surface or submerged in the well).

It is useful to extract from the well the liquid hydrocarbons produced but also the production gas, even if initially this one was not a production objective. Indeed, if it is not extracted, it can increase pressure well and alter the operation of the pump (life or efficiency). It is, of course, possible to allow production gas to flow freely within the well (for example through an annular space) but this gas can endanger the integrity of certain parts of the non-H2S-service well (ex. H ₂ S gas can react with certain metals and cause corrosion cracking).

It is also possible to provide pumps for pumping mixtures of gases and liquids. Nevertheless, these pumps may have operating difficulties if the volume proportion of gas relative to the total volume (or GVF for gas volume fraction) pumped exceeds a certain threshold even very temporarily. These situations can arise especially in case of occurrence of gas plugs during the production of hydrocarbons. The massive inflow of gas at the suction of the pump can cause malfunctions of the pump with accelerated damage and a mechanical stop of this one following the repeated lack of lubrication or extended periods of non-flow due to gas blocking (or "gas lock" in English).

Such systems are not free of defects as mentioned above. The present invention improves the situation.

For this purpose, the present invention provides an evacuation device without passing through the pump and allowing a simple and inexpensive evacuation of gases especially in the case of combined production of gases and liquids.

The present invention thus aims at a device for discharging gaseous and liquid fluids suitable for being positioned in a hydrocarbon production well, the well comprising a wellhead and a wellbore, in which the device comprises:

an evacuation tube, one end of said tube being able to be connected to a pump positioned in the extraction well for pumping at least one liquid; an insulator in contact with the tube and able to block a flow of gaseous fluid contained between a wall of the tube and a wall of the well, of a first space formed between the insulator and the bottom of the well to a second space formed between insulation and wellhead;

- At least a first opening made at an opening dimension on a wall of said tube adapted to allow a flow of a gas of said first space in said tube;

- At least a first valve equipping the at least first opening, the valve being adapted to block a fluid flowing in said tube to the first space. It is possible to designate the first space as being the lower annular space below the insulator (or "bottom") and the second space as the upper annular space above the insulator (or " in the upper part ") The opening made in the tube allows the gas present in the first space to be injected into the tube and thus allow it to be extracted at the same time as the liquid hydrocarbons circulating in the evacuation tube, but without passing through the pump. Furthermore, this injection makes it possible to limit the formation of hydrates on the evacuation of the gas, especially when the environment near the wellhead is cold (eg wells in a polar environment), allowing the gas to come into contact liquid hydrocarbons and reheat it.

Insulation is more often called "packer" (terminology of English origin). The insulation may be a circular ring whose inner surface is in contact with the tube (or "tubing" in English) and whose outer surface is adapted to be in contact with the walls of the well (or "casing" in English) . These contacts can be waterproof contacts.

The term "a valve equipping an opening" means that the valve is able to control the flow of fluid through the opening.

In order for the injection of the gas to proceed correctly, it is useful for the pressure in the annular space (ie outside the tube) to be greater than the pressure in the tube at this opening: these conditions are obtained by appropriate operating conditions.

Of course, if the first pressure can be greater than a second pressure in said tube at a given time, this does not mean that the first pressure is always greater than the second pressure at any time. Indeed, it may happen that the second pressure is, for example, occasionally greater than the first pressure depending on the operating conditions of the well (eg occurrence of gas plugs, start or stop of the pump, etc.).

Moreover, if there is no dimension below the insulation for which the first pressure is greater than the second pressure, the valve (for example, anti-return) allows to continue to produce the liquids and accumulate the gases in the annular space causing the rise in pressure the first space (due to the natural production of gas by the well). In one embodiment, the device may comprise at least a second opening made on a wall of said tube adapted to allow a flow of a gas of said first space in said tube, at least a second non-return valve being mounted on the at least one second opening, the at least one second non-return valve being able to block a fluid present in said tube to the first space.

The second opening may be located at a different coast from said opening dimension or at said opening dimension. This second opening provided with a non-return valve allows the device to adapt to the operation of the well. Indeed, it can be complex to determine exactly the dimension of the tube at which the pressure equilibrium knowing that it can be variable. Thus, if several openings provided with valves are made on the tube, at different dimensions (eg every 10m, on the last 100 meters before the insulator and below this), only the valves positioned at a rating for which the pressure inside the tube is lower than the pressure outside the tube can inject. This plurality of openings thus allows increased flexibility of the device.

Moreover, if several valves are positioned at the same dimension, it is possible to choose non-return valves so that their opening characteristics are different (eg the force required to apply to the valve so that it opens). Thus, the number of open valves at the same rating may depend on the pressure difference between the inside and outside of the tube: if this difference is small, only some valves open while if this difference is very important, more valves open. For the purpose of optimization, successive valves can be controlled by electric or electromagnetic hydraulic control.

Furthermore, the valve is characterized by its opening conditions and the passage section (diameter, shape, etc.) and it is then possible to modulate these parameters in order to adapt to the operating modes of the production well (possibly by changing the valve, adding an internal calibration or modulating its opening remotely from the surface).

The first valve can be advantageously interchangeable from an inside of the evacuation tube. For example, it is indeed possible to mount this valve on a mandrel (or "mandrel" in English). Thus, if the second pressure is occasionally greater than the first pressure, it is possible to limit the return of hydrocarbon fluid flowing in the tube to the annular space.

By lowering tools from the wellhead into the discharge tube, it can be easy to retrieve and change the valve to perform maintenance or adjustment of these features.

The device may furthermore comprise at least one gas-liquid separation device connected to another end of the tube (for example at the surface) or at least one gas-liquid separation device placed upstream of the pump (ie in front of the zone). suction of the pump into the well).

The second pressure can be determined according to at least:

a distance from the connection of the tube to said pump; a characteristic of pressure evolution of an operating fluid;

- An overpressure characteristic of the pump.

The distance between the opening dimension of a valve and the connection of the tube to the pump is called "distance from the connection of the tube to said pump".

The term "pressure evolution characteristic of a fluid" is used to describe a parameter for estimating the pressure variation in a tube along it, for example for a vertical displacement Δζ. This parameter can represent the hydrostatic pressure variations of the fluid Az. p. g with g the constant gravitational and p the density of the fluid. In addition or alternatively, this parameter can be affected by the variations in velocities and hydrodynamic pressures of the fluid which induce, for example, a sliding between phases and therefore a variable equivalent density, hence the difficulty (ie related to the setting in motion of the fluid, friction, etc.).

The "pump overpressure characteristic" is the pressure difference between the pump outlet and the pump inlet.

In a given embodiment, the first pressure can be determined according to at least:

a distance from the connection of the tube to said pump;

- a distance to a gas-liquid interface;

- A characteristic of pressure evolution of a liquid operating fluid; - A characteristic of pressure evolution of a gaseous operating fluid.

The installation of a pressure sensor with surface transmission will adjust the valve openings to optimize production and protect the pump to increase its life.

The device may further comprise, connected to another end of the tube, a gas-liquid separation device.

Most often, this separation device may be at the surface in order to obtain a liquid discharged from the gas injected at the opening.

The insulation can be positioned on the tube so that a gas with H ₂ S can flow into the first space without damaging walls of said well. Thus, it is possible to protect the well walls that do not support acid gases such as H ₂ S while maintaining a large volume in the annular space.

The present invention also aims at a gaseous liquid evacuation system comprising:

- a hydrocarbon production well;

- a pump positioned in the production well;

an evacuation device as described previously and positioned in the production well;

The pump is then connected to the evacuation tube of said evacuation device.

The injection dimension can be chosen as low as possible in the case where the gas flow is not very variable, thus making it possible to reduce the need for power of the pump, especially when there is little liquid produced. Conversely, if the gas flow rate is variable, a high injection side avoids an impact on the pressure drops in the tubing and therefore on the operation of the pump.

Other features and advantages of the invention will become apparent on reading the description which follows. This is purely illustrative and should be read in conjunction with the attached drawings in which:

- Figure 1 illustrates a particular embodiment of an evacuation device mainly production liquid in one embodiment of the invention;

FIG. 2a is a representation of an evolution of the pressure curve within the device as a function of a depth; - Figure 2b illustrates a temporal evolution of pressure for a given depth but low.

Figure 1 illustrates a particular embodiment of the discharge device mainly production liquid in an embodiment of the invention.

During the exploitation of a well 100, an eruptive well can gradually unfold and lose its eruptive character. As a result, artificial extraction methods can be implemented in order to raise the surface hydrocarbons produced underground (ie passing through the well wall through the perforations or connections of the well at the bottom of the well, arrow 104) but not having enough energy to rise naturally in steady state or transient.

To overcome these problems, it is possible to install at the bottom of a well (i.e. in a naturally immersed hydrocarbon zone) a pump 102, for example a submerged centrifugal pump.

This pump 102 is connected to a discharge tube 101 for raising the mainly liquid hydrocarbons pumped to the surface.

In order to prevent this pump from getting stuck or damaged by the presence of "gas plugs" (ie the sudden appearance of gas in liquid hydrocarbons), it is possible to use a system separating the gas from the liquid before the pumping phase.

In addition, there are impellers that tolerate very high gas contents (eg POSEIDON type impeller) that can operate with a volume fraction of the gas up to about 100% (or GVF for "Gas Volume Fraction"). The submerged pumps are equipped with a stack of these impellers in series and possibly impulseers of other types (eg POSEIDON submersible pumps). Nevertheless, the massive inflow of gas at the suction of this type of pump (eg gas volume fraction exceeding 60%) can lead to malfunctions of the pump and mechanical shutdown of the pump due to repeated lack of lubrication and insufficient pressure elevation. Thus the liquids (ie the hydrocarbons) are sucked into the pump (arrow 105) to be brought up to the surface (arrow 107) while the gas produced (ie passing through the perforations or the connections of the welll 03) rises in the well ( arrows 106, 108) in the annular space formed by the walls of the well 100p and the walls of the evacuation tube 101.

It is possible to raise this gas by the annular space to the surface (dimension z ₀ ) but this method has drawbacks. Indeed, it is necessary to provide openings and / or valves on the insulator 109 (or "packer" in English) so that the gas can flow. The presence of these openings and / or valves greatly complicates the safety devices implemented at the wellhead 10Ot (for example SCSSV or "surface-controlled subsurface safety valve" in English).

Moreover, it is possible that certain parts of the well have a so-called "casing non H ₂ S service" architecture. This type of architecture means that certain walls of the well (ie the "casing" in English) can be damaged or weakened by the circulation or the presence of hydrogen sulphide: hydrogen sulphide can, indeed, damage some metals by cracking. The parts of the well "casing non H ₂ S service" are sometimes wellhead, located on a few tens of meters (50 m approximately). Thus, it is advantageous not to circulate gas in the last meters of the well in order to preserve the integrity of its walls. It would be possible to provide a special tube extending in the annular space of the insulator 109 at the surface and adapted to a gas flow comprising H ₂ S but this tube can make expensive and complex safety devices at the head wells and intervention operations on the well requiring heavy means ("work-over" in English).

Having a specific annular outlet on the surface complicates the wellhead, increases the need for a safety barrier and induces risks of hydrate formation.

Thus, one or more opening (s) is (are) made in discharge tube 101 below the insulation 109 and one or more valve (s) 1 1 1 is (are) installed (s): this valve can be a gas-lift type valve because this type of valve is proven in this type of situations and allows a simple, configurable and inexpensive installation. In addition, these valves can be mounted on a mandrel so as to interchange easily and possibly adjust their opening depending on the operation of the well. This valve optionally allows the passage of gas between the annular space to the discharge tube when the pressure in the annular space at the level of this valve is greater than the pressure in the evacuation tube 101 at this valve. The passage of the gas can be conditioned also by an activation pressure related to the characteristics of the valve or a hydraulic or electrical command controlled from the surface. It is possible to connect to this opening a tube extending to the surface. Nevertheless, it may be advantageous to provide no tubes: the production gas mixes with the mainly liquid hydrocarbons at the level of this valve and rises in the extraction tube with the liquid effluent (in dissolved form or in the form of bubbles) . Thus, the device remains simple and inexpensive to implement or maintain in condition. It is then possible to achieve a separation of the gas (arrow 1 13) and the liquid (ie hydrocarbons, arrow 1 14) at the surface, at the wellhead for example.

It is possible to provide several valves (1 1 1, 1 12) along the tube 101. Indeed, it can be effective to reinject the gas as low as possible into the production tube. However, it is complex to know the exact re-injection rating possible, knowing that this can be variable when the well is in operation (i.e. when hydrocarbons are raised from the bottom of the well 10Of). Indeed, this reinjection rib requires that the pressure in the annular space at a given dimension is greater than the pressure in the evacuation tube 101 at this same dimension: the pressure at a given dimension may depend on the characteristics specific to the pump but also may vary depending on the time (especially in case of depletion of the well).

It is also possible to provide several valves close vertically (ie in a predetermined range of dimension). This makes it possible to increase the passage cross section beyond the maximum diameter of the orifices for a given mandrel or to vary the passage section by opening when necessary the other valve (s): if the pressure increases strongly and / or brutally in space annular, the number of open valves (ie to reduce the pressure) can increase significantly.

In addition, the positioning of the insulator 109 to a dimension z _nc close to the wellhead 101OT makes it possible to increase the gaseous volume of the annular space. This makes it possible to avoid jolts of pressure in case of occurrence of gas plugs: the volume of the annular space allows a great inertia of this space and limits the pressure variations in case of flow variation. This reinjection in the high position makes it possible to limit the "submergence" (ie liquid height above the pump suction in the annular space) thus to reduce the bottom pressure and increase the flow rate.

Advantageously, the injection of the production gas into the hydrocarbons makes it possible to limit the formation of hydrates, especially if the well is a submarine well or a well drilled in a cold zone. Indeed, the hydrocarbons are relatively hot and avoid excessive cooling of the production gas.

Figure 2a is a schematic representation 200 of an evolution of the pressure curve within the device as a function of a depth.

Production pressure PPROD is the pressure at the Z _PRO D dimension (ie the perforation dimension or connections of the well 1 03). Of course, from the ZPROD dimension (point 201), the pressure decreases going back up the wall of the well to the interface between the liquids and the gases (dimension Z |, point 205), outside the tube of evacuation: the slope of this segment [201 -205] corresponds substantially to the hydrostatic pressure variation of the liquids present at the bottom of the well (the liquids being substantially static). Of course, above the dimension z (point 205) and up to the insulation (ie the dimension ZNC, point 207), the pressure also decreases but more slowly. Indeed, the slope of the segment [205-207] corresponds substantially to the hydrostatic pressure variation of the production gas (to which may be added a component of hydrodynamic variation related to the friction of the fluid moving within the annular space) . On the side z _P i to the dimension z _P2 , is the pump 102. The pump inlet pressure is the pressure P _E p at point 202 of Figure 2a. The pressure at the pump output is P _S p pressure at point 203 as PSP = PEP + ΔΡ ΔΡ with a pumping-related pressure (ie characteristic of the booster pump). The pressure in the discharge tube is represented by the half-line [203-206]. The slope of this half-line substantially corresponds to the variation of hydrostatic pressure of the liquids present in the evacuation tube 110 (to which may be added a component of hydrodynamic variation related to the friction of the fluid moving within the tube 101) . The half-line [203-206] and the segment [205-207] intersect at point 206, the point of equilibrium between the pressures within the evacuation tube 110 and outside it (in the annular space). Thus, the pressure in the annular space above the dimension z _E and up to the dimension z _NC is greater than the pressure in the tube 110 for the same dimension. If a valve 1 1 1 type "gas-lift" is installed on the wall of the tube at a rating in the range [z _E; z _N c], this valve 1 1 1 can reinject the gas within the tube 1 01.

In order to determine the dimension z _E (or an estimate of this dimension z _E ), it is possible to solve the following equation:

( ^z _/ ^- · ¾) ■ dPs-uq + (¾-Zj). (dP _s _ _gas + dP _D _ _gas )

= -ΔΡ + (z _E - z _P2 ). (dP _s ^ _liq + dP _D _ _Uq ) with dP _s _ _uq the density of the liquids present in the annular space multiplied by the constant g of gravity, dP _s _ _gas the density of the production gases present in the annular space multiplied by the constant g of gravity, dP _D -gaz a dynamic pressure component of the gas depending on the speed of displacement of the production gas in the annular space and characteristics of this annular space (shape, size, roughness of walls, etc.), dP _D _ _Uq a dynamic pressure component of the liquid moving in the evacuation tube according to the speed of displacement of this liquid in the tube and characteristics of this tube (shape, size, roughness walls, etc.). This formula can be further approximated by considering that the dynamic pressure component is zero or negligible.

The equation above approximates that the height of the pump is low in front of the height (z _E - z _P2 ) and therefore AP ₁ (pressure difference between point 202 and point 204) is low. Nevertheless, it is possible to take into account the height of the pump with the following formula:

( ^Z / ^{- Z} PI) - dPs-uq + (¾-Zj). (dP _s _ _gas + dP _D _ _gas )

= -ΔΡ + (z _E - z _P2 ). (dP _s _ _liq + dP _D _ _Uq )

Of course, this FIG. 2a does not respect the scales and the proportions of the different dimensions or pressures.

In practice, the interface dimension zi is very close to the production dimension and the overpressure of the pump is relatively high compared to the hydrostatic pressure variation of the gas in the annular space (slope of the straight line (205,206)) .

Figure 2b illustrates a temporal evolution of pressure for a given depth. The pressure representation as shown in relation to FIG. 2a does not show the temporal variations of the pressure. Indeed, the pressure can change due to the depletion of the tank and due to the presence of gas plugs.

The curve 21 0 shows the variation of pressure within the annular space of the device presented previously at a dimension z _x.

Curve 21 1 shows the variation of pressure within the evacuation tube 110 at the same dimension z _x.

At this dimension z _x , the pressure of the curve 210 is predominantly greater than the pressure of the curve 21 1 (except during the periods of time [t-ι, t ₂ ] [t ₃ , t ₄ ] and [t ₅ , t ₆ ]). It is thus possible to determine a proportion of average time during which the pressure 21 0 is greater than the pressure 21 1 (for example, by carrying out the determination over a period of 3 hours or one day). If this determined proportion is greater than a predetermined threshold, it is possible to consider that the dimension z _x is greater than the dimension z _E. For example, this predetermined threshold may be equal to 50%, 80% or 90%.

Of course, the present invention is not limited to the embodiments described above as examples; it extends to other variants.

Other achievements are possible.

For example, the discharge tube is described as being centered in wells thus forming an annular space around this tube. It is also possible that this tube is not centered in the well, "the annular space" then being misnamed as well.

Moreover, the embodiments have hydrocarbon exploitation wells but the devices and systems presented are not limited to this embodiment. Indeed, it is possible to use these systems or devices in any well (or more generally any cavity) simultaneously producing gas and liquid.

Furthermore, the bottom separation may be partial, that is to say the liquid effluent may contain gas and the gaseous effluent may cause liquid according to the operating conditions.

Claims

1. Device for discharging gaseous and liquid fluids suitable for being positioned in an extraction well, the well comprising a wellhead and a wellbore, in which the device comprises: an evacuation tube, an end of said tube being able to be connected to a pump positioned in the extraction well for pumping at least liquid;

an insulator in contact with the tube and able to block a flow of gaseous fluid contained between a wall of the tube and a wall of the well, of a first space formed between the insulator and the bottom of the well to a second space formed between insulation and wellhead;

- At least a first opening made at an opening dimension on a wall of said tube adapted to allow a flow of a gas of said first space in said tube; - At least a first control valve equipping the at least first opening, the valve being adapted to block a fluid flowing in said tube to the first lower space.

2. Device according to claim 1, wherein the device comprises at least a second opening made on a wall at a second side, said second opening being located at a different coast of said opening dimension.

3. Device according to claim 1, wherein the device comprises at least a second opening made on a wall at a side located at said opening dimension.

4. Device according to claim 1, wherein at least the first valve is interchangeable from inside the evacuation tube.

5. Device according to one of the preceding claims, wherein the device further comprises at least one gas-liquid separation device connected to another end of the tube or at least one gas-liquid separation device placed upstream of the pump. .

6. Device according to one of the preceding claims, wherein the insulator is positioned on the tube so that it allows a gas comprising H ₂ S can flow in the first space without damaging walls of said well.

Fluid evacuation system comprising:

- a hydrocarbon production well;

a pump positioned in the hydrocarbon production well; - An evacuation device according to one of claims 1 to 6 positioned in the hydrocarbon production well; wherein, said pump is connected to the evacuation tube of said evacuation device.