Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
  • E21B43/122—Gas lift
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
  • E21B43/126—Adaptations of down-hole pump systems powered by drives outside the borehole, e.g. by a rotary or oscillating drive
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
  • E21B43/128—Adaptation of pump systems with down-hole electric drives
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
  • E21B43/129—Adaptations of down-hole pump systems powered by fluid supplied from outside the borehole

Definitions

• the present invention relates to a plant and a method for producing hydrocarbons.
• the present invention also relates to a method of upgrading a hydrocarbon production facility.
• Figure 1 shows a diagram of different productivity characteristics in relation to well bottom flow pressure and flow rate, denoted Q.
• the bottom flow pressure of the well is indicated in Figure 1 by the reference sign BHFP, abbreviation of the equivalent English expression "Bottom Hole Fluid Pressure”.
• Figure 1 shows three characteristics 102, 112 and 122 of different wells. These wells differ in their natural lift gradient, as defined by the following equation:
• Lg * 10.2 where Lg is the natural lift gradient of the well
• BHP is the downhole pressure in bars (abbreviation of the equivalent English expression "Bottom Hole Pressure")
• THP is the pressure at the wellhead in bars (abbreviation from the English term “Tubing Hanger Pressure”);
• H is the vertical depth of the well in m.
• the curves 104 and 114 of FIG. 1 respectively correspond to the performance of a so-called light gas lift and the performance of a so-called gas lift.
• the so-called light gas lift has two operating points with the curve well 102 of which point 106 allowing a larger flow, Q, production of the well.
• the so-called lightweight gas lift has no operating point with the lower Lg wells like the wells of curves 112 and 122.
• the gas lift said weak thus allows the exploitation of wells of Lg between 0.6 and 1, 0.
• the introduction of the so-called heavy gas lift then ensures the operation of the curve well 112 at the operating point 112 but does not make it possible to operate the curve well 122 with which it has no operating point.
• the gas lift says strong allows the exploitation of wells of Lg between 0.3 and 0.5. In other words the gas lift, even strong, is insufficient to exploit the wells of Lg too low.
• the invention proposes a hydrocarbon production plant, comprising:
• a hydrocarbon production line comprising:
• a line for injecting the gas under pressure into the hydrocarbon production line the injection line being connected to the source of gas under pressure
• a pneumatic pump power supply motor disposed on the gas injection line under pressure and adapted to be rotated by expansion of the gas under pressure.
• the installation comprises a mechanical transmission shaft connecting the pneumatic motor to the pump.
• the pneumatic motor is an electric generator.
• the pump in the well is of the electric submersible type or of the progressive cavity type.
• the pump is disposed at the bottom of the well.
• the injection line opens at the bottom of the well, preferably in the production tube of the hydrocarbon production line.
• the pneumatic motor is at the wellhead.
• the pneumatic motor is at the bottom of the well.
• the injection line opens into the evacuation tube of the production line, downstream of the circulation pump.
• the invention also proposes a method for operating a gas injection-activated hydrocarbon production well, comprising:
• step b) actuating a hydrocarbon circulation pump of the well by means of the energy recovered in step b);
• the gas under pressure is at a pressure greater than or equal to 70 bars before the expansion.
• the pressurized gas is expanded by the pneumatic motor at a pressure of less than or equal to 30 bars.
• the invention also proposes a method of upgrading a hydrocarbon production facility, the installation comprising:
• a hydrocarbon production line comprising:
• a line for injecting the gas under pressure into the hydrocarbon production line the injection line being connected to the source of gas under pressure; the method comprising:
• a pneumatic pump power supply motor adapted to be rotated by expansion of the gas under pressure.
• Figure 1 is a diagram of different productivity characteristics in relation to well bottom flow pressure and flow rate
• Figure 2 is a schematic sectional view of an embodiment of a hydrocarbon production facility
• Figure 3 is a schematic sectional view of an embodiment with gas lift of the hydrocarbon production facility
• Figure 4 a diagram of the pressure evolution as a function of the depth in a well for different methods of exploitation of the well
• Figure 5 is a schematic sectional view of another embodiment with gas lift of the hydrocarbon production facility.
• the hydrocarbon production facility 20 comprises a hydrocarbon well 22.
• the installation comprises a production line having a production tube 24 in the well 22 and a tube 26 on the discharge surface from the production tube 24.
• the tube 26 on the surface allows for example the evacuation to a reservoir 28 for storing the hydrocarbon product.
• the tube 26 at the surface can also be used to evacuate the products 82, brought up by the production tube 24 and comprising hydrocarbons 80, to devices (not shown) for separating the products 82.
• These product separation devices 82 can in particular separate water, gas and oil.
• the installation 20 comprises a hydrocarbon circulation pump of the well 22 in the production line making it easier to raise the hydrocarbons 80 by the production tube 24.
• This pump 40 can be placed at the bottom of the well 22 and is the remainder of this document referred to as the "bottom pump".
• Such a bottom pump 40 makes it possible to ensure or increase a production of hydrocarbons by the well 22, in particular in cases where the activation by injection of gas under pressure is insufficient to obtain a lowering of the hydrostatic pressure. or against pressure, of the well 22 making it possible to exploit the well 22.
• the pump 40 may be disposed in the tube 26 for evacuation at the surface. Such an arrangement of the pump 40 also makes it possible to increase the production by lowering the back pressure of the well 22 while facilitating the maintenance of the pump 40 which is then more accessible.
• the pump 40 is driven by a turbine 30.
• the positioning of the turbine 30 is embodied in the figures on the one hand by means of discontinuous lines and on the other hand by the representation schematic of blades 32 of the turbine 30.
• This turbine 30 is disposed in a line 36 of gas 38 under pressure so as to be rotated by the expansion of the gas 38 under pressure.
• the turbine 30 supplies the pump 40 with energy, this energy coming from the expansion of the gas 38 under pressure.
• the turbine 30 can be replaced by any other type of pneumatic motor, an engine pneumatic converter converting stored energy in a compressed gas into mechanical energy.
• the turbine can be replaced by any other hydrodynamic-type tire or a pneumatic type volumetric motor, the air motor then comprises a relaxation chamber whose volume is variable.
• the pneumatic type volumetric motor proposed can thus correspond to a pneumatic piston engine circumferential.
• the air motor such as in the form of the turbine 30, may be provided with a deflection, otherwise known as "bypass".
• the proposed installation may comprise a speed controller integrated in the pneumatic motor.
• the speed of the turbine or the pneumatic motor can be transmitted on the surface in the form of a sound via the production tube 24 of the well 22. impact frequency at each rotation of the pneumatic motor to be characteristic of the rotational speed of the pneumatic motor.
• the transmission of the kinetic energy of the turbine 30 to the pump can be achieved by means of a shaft 42 (shown in broken lines) rotated.
• This shaft 42 of mechanical transmission connects the turbine 30 to the pump 40.
• the mechanical connection between the turbine 30 and the pump 40 comprises a gear 44 for modulating the speed of rotation of the shaft 42 causing the actuation of the pump 40.
• the shaft 42 is then split into two parts, a part connecting the turbine 30 to the gear 44 and another part connecting the gear 44 to the pump 40.
• Such a gear can be of the magnetic type to achieve a high conversion ratio.
• the mechanical connection between the turbine 30 and the pump 40 may also include a clutch (not shown).
• the shaft 42 may comprise various hinges 46.
• the transmission to the pump 40 of the energy recovered by the turbine 30 is then performed without additional energy conversion.
• the turbine 30 may be an electric generator.
• the energy transmitted from the turbine 30 to the pump 40 is then electrical to overcome the mechanical constraints associated with the use of the shaft 42 of mechanical transmission especially when the trajectory of the well 22 is too aggressive.
• the bottom pump 40 may be of the electric submersible type (pump type also referred to as "Electric Submersible Pump” abbreviated as "ESP").
• ESP Electrical Submersible Pump
• the bottom pump 40 may be of the progressive cavity type (pump type also referred to as "Progressive Cavity Pump” abbreviated as "PCP").
• the use of a progressive cavity pump makes it possible to stabilize the well 22 by allowing a direct control of the flow rate of the well 22.
• the mechanical transmission of the power of the pneumatic motor in the form of a turbine 30 at the pump 40 limits the presence of electrical equipment downhole. In such a case of mechanical power transmission, the life of the installation is improved due to the independence of the proposed installation to such electrical equipment downhole 22.
• the pressurized gas 38 driving the turbine 30 comes from a source 34 of pressurized gas, at the surface with respect to the well 22, the source illustrated here in the form of a reservoir.
• sources 34 of pressurized gas are generally available on the surface in known hydrocarbon production facilities.
• the presence of pressurized gas sources on the surface is particularly required in the case of installations activated by injection of pressurized gas into the production line (production process also known as "gas lift"). .
• the proposed installation 20 allows the driving of the bottom pump 40 facilitating the production of hydrocarbons and this in the absence of additional power distribution network.
• the proposed installation 20 is particularly advantageous when the production facility is remote from any electrical production site or inhabited place.
• the upgrade of a hydrocarbon production facility corresponds to the adaptation of existing facilities to the previously described solution.
• the devices already present before the upgrade of the installation are for example the well 22, the production line, the source 34 of pressurized gas and the injection line 36 of the pressurized gas 38 in the production line.
• Such an upgrading method adds the bottom pump 40, or the surface pump, and the turbine 30 or other pneumatic motor to these devices already present in the installation to be leveled.
• the method comprises placing the pump 40 in the well 22 or on the surface and placing it on the injection line 36 of the turbine 30 for supplying the pump with energy.
• the upgrading method can of course include the implementation of any other device described in this document and in particular the establishment of one, more or all devices in interaction with the pump 40 and / or with the turbine 30, such as for example the mechanical transmission shaft 42 and the gearbox 44.
• Such a method firstly comprises supplying pressurized gas 38 from the source 34 of pressurized gas, at the surface. This step allows the recovery of energy already available on production facilities by gas lift.
• the source 34 may for example provide the gas 38 before expansion at a pressure greater than or equal to 70 bars or of the order of 65 bars.
• the pressurized gas 38 may be expanded by the turbine 30 to a pressure of less than or equal to 30 bar.
• This energy recovered in kinetic form is retransmitted in this form or in another form, such as in the form of electrical energy, to the pump 40 in the well 22 for its actuation.
• the bottom pump 40 contributes to the surface rise of the hydrocarbons 80 of the production well via the hydrocarbon production line to the tank 28.
• the gas 38 after expansion can be injected into the hydrocarbon production line.
• the gas under pressure 38 after expansion then has a lower injection pressure compared to the case where the pressurized gas 38 is injected into the production line without prior expansion or too high pressure such as 70 or 65 bar.
• the lower injection pressure makes it possible to avoid excessive instantaneous flow (also known as steam break through). Such a phenomenon occurs in fact when the pressure drop provided at the bottom of the well by the gas lift is too great and adversely affects the productivity of the well.
• the lower injection pressure also makes it possible to avoid runaway in the event of instantaneous vaporization (also known as the "steam flashing" phenomenon).
• the system can safely limit the over-cooling, difference between the hydrocarbon temperature and the evaporation temperature of these hydrocarbons at the same pressure (over-cooling corresponding to the English term "sub-cool”).
• the over-cooling can then be lower without risk of runaway, that is to say without risk of spraying.
• the hydrocarbons to be produced are hotter, less viscous and therefore easier to extract.
• the gas injection line 36 opens at the surface into the evacuation tube 26 of the production line.
• the expanded pressurized gas 38 is thus injected into the surface portion of the production line referred to as "flow line” (of the English expression "flow line”). Injection of the pressurized gas 38 into the surface portion of the production line makes it possible to reduce the hydrostatic pressure of the production line even when the pressure after expansion is low.
• the pressurized gas 38 is intended to be injected into the production line at the level of the production tube 24, so as to activate the production of hydrocarbons 80.
• the injection line 36 is in the form of an annular around the production tube 24.
• the gas 38 is expanded by the turbine 30 before being injected into the production line of the well 22.
• the production of hydrocarbons is facilitated on the one hand by the bottom pump 40 and on the other hand by the injection of gas.
• the injection of gas into the production line of the well 22 as illustrated in FIG. 3 corresponds to a gas lift technique, i.e. to activation by gas injection.
• the injection of the expanded gas 38 is carried out "downhole” above the location of the bottom pump 40, directly in the production line at the level of the tube 24.
• the gas injection is performed downstream of the pump in the production line.
• the term "downhole” is used in this document as characterizing a positioning close to the geological layers forming the reservoir of the hydrocarbon reservoir exploited by the well 22. This expression is used in opposition to the expressions “wellhead "and” on the surface ".
• the term “surface” characterizes in this document a positioning at ground level, above the ground or immediately below the ground. A device disposed on the surface can thus correspond to a device buried at a negligible depth relative to the depth of the well.
• the expression “at the wellhead” characterizes in this document a “surface” positioning, in line with the well, that is to say at the vertical of the well. Thus the distance between a "wellhead” positioning and a “well bottom” positioning is substantially equal to the length of the trajectory of the well 22.
• the mixed lines modeling the interrupted view of the well 22 in the figures separate from the one part the wellhead and the surface, above the mixed lines, the well bottom 22 on the other hand, below the mixed lines.
• the turbine 30 is disposed at the wellhead 22.
• the arrangement of the turbine 30 at the surface makes it possible to avoid that the expansion of the pressurized gases 38 at the turbine 30 does not cool the hydrocarbon 80 downhole 22.
• the cooling of the hydrocarbon 80 by the gas may for example cause the formation of deposit, such as the formation of deposit paraffin wax for paraffinic hydrocarbons, otherwise referred to as paraffinic crude.
• the embodiments illustrated in FIGS. 2 and 3 then have the advantage of facilitating the management of the risk of deposit formation which is limited at the level of the injection of the expanded gas 38 into the production line, either on the surface of the well or at the wellhead, respectively.
• the embodiment illustrated in FIG. 3 possibly makes it possible to have more diameter.
• Such an embodiment is then particularly preferred for the production of hydrocarbons present in the form of "heavy oil".
• the bottom pump 40 is preferably of the PCP type.
• the use of the PCP type pump 40 for the production of "heavy oil” makes it possible to stabilize the activation by gas injection and better control of the flow, especially at the beginning of production after the injection of the gas under pressure. in the production line.
• the pressurized gas 38 can be heated after having been expanded by the turbine 30.
• the surface positioning of the turbine 30 also contributes to facilitating the architecture of the installation. Indeed, in the mechanical transmission variants of the energy of the turbine 30 to the pump 40, the gearbox 44 can be very bulky, particularly in the case where the gear 44 is of the magnetic type.
• the surface arrangement of the turbine 30 then allows the surface arrangement of the gearbox 44 between the turbine 30 and the pump 40, the surface being less subject to space constraints than the bottom of the well 22.
• FIG. 4 shows a diagram of the evolution of the pressure, P, in function the vertical depth, H, in the well 22.
• the point BH abbreviation of the expression English "Bottom Hole” corresponds to the vertical depth at the bottom of the well.
• the installation illustrated in FIG. 3 allows the pressure to follow the curve 140 presenting a decrease in pressure 142 at the depth at which the pump 40 is disposed. This reduction in pressure 142 makes it possible to obtain a low downhole pressure at point 144.
• This low pressure at point 144 is to be compared with the pressure obtained at point 132, which is the hydrostatic pressure of the hydrocarbons at the bottom of the well.
• Point 132 is the point of the hydrostatic pressure curve in broken lines 130 at the depth at the bottom of the well.
• the curve 130 corresponds to the evolution of the pressure in the well in the natural state, that is to say in the absence of particular devices in the well to facilitate the production of the well.
• the downhole pressure obtained using the proposed installation corresponds, with respect to hydrostatic pressure point 132 downhole 22, to a pressure drop 146 (also referred to as "draw down”). ) promoting the extraction of hydrocarbons from the well 22.
• the use of a portion of the energy of the gas under pressure to actuate the bottom pump 40 and the other part of the pressurized gas energy used in gas lift allows double-strand extraction of hydrocarbons from well 22 from a single source.
• the pressure as a function of the depth follows the curve in thin line 134 to reach a downhole pressure at point 136.
• This pressure at the bottom of the well 22 allows a lower pressure drop 138 than the pressure drop 146 allowed by the proposed installation.
• the double-effect extraction from a single source then allows a greater production of the well 22 in comparison with the use of all the energy of the pressurized gas gas lift.
• the injection of the pressurized gas after the expansion corresponds in fact to a use of the gas lift in its effective range, such as for pressures of the order of or less than 30 bar, the excess energy being used in the form of mechanical energy for driving the pump 40.
• pressure levels of the pressurized gas 38 of the order of 70 bars or 65 bars can be achieved with pressure levels of the pressurized gas 38 of the order of 70 bars or 65 bars.
• the use of pressure levels of the order of 70 bar or 65 bar limits the risk of wear of the installation and increases the number of usable technologies compared to the use of higher pressures in gas lift to obtain a efficiency comparable to that of the proposed double-effect extraction.
• FIG. 5 shows an embodiment of the installation where the turbine 30 is disposed at the bottom of the well.
• This embodiment is particularly advantageous when the hydrocarbons 80 to produce are very hot.
• the heat of the hydrocarbons 80 to be produced limits the influence on the production of the cooling of the hydrocarbons 80 by the injection of the pressurized gas 38 expanded.
• the pump 40 may be of the high-speed rotodynamic type, preferably a high-temperature electric submersible pump (pump type also designated by the expression English “Electric Submersible Pump High Temperature” abbreviated to "ESP-HT")
• ESP-HT Electric Submersible Pump High Temperature
• the arrangement of the turbine 30 downhole may also be considered when it is intended to preheat the pressurized gas 38 in the annular portion of the injection line 36, to limit the cooling of the hydrocarbons to be produced.
• the pressurized gas before expansion is hotter than in the embodiments described previously in FIG. reference to Figures 2 and 3.
• FIG. 5 with the downhole air motor 22, illustrated in the form of a turbine 30, is preferred to the embodiment illustrated in FIG. 3 with the wellhead motor for the aforementioned well stimulation phase. 22 when the hydrocarbons are heavy oils.
• the embodiment illustrated in FIG. 5 is also preferred for wells 22 of standard crudes.
• the embodiment illustrated in FIG. 3 is preferred for the aforementioned phase of ramping up the operation of the well 22 when the hydrocarbons are heavy oils.
• the injection of gases under expanded pressure can be carried out for the same hydrocarbon production facility both in the production tube 24 downhole and in the discharge tube 26 at the surface.
• Such a variant thus corresponds to the combination of the embodiments illustrated in FIG. 2 and in FIG.
• the injection line of the pressurized gas may comprise one or more boosters (not shown) to increase the pressure of the gas under pressure upstream of the turbine.
• boosters also known as the boosters to increase the pressure of the gas under pressure upstream of the turbine. This increase in pressure allowed by the boosters makes it possible to have more energy for the turbine and / or more energy after the expansion performed for the turbine for the activation of the well by injection of the expanded gas. This increase in pressure by the boosters ultimately allows an even greater improvement in the production of the well.

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• Life Sciences & Earth Sciences (AREA)
• Engineering & Computer Science (AREA)
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• Mining & Mineral Resources (AREA)
• Physics & Mathematics (AREA)
• Environmental & Geological Engineering (AREA)
• Fluid Mechanics (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
• Jet Pumps And Other Pumps (AREA)
• Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)
• Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

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• 2013
  • 2013-10-14 FR FR1359993A patent/FR3011874B1/fr not_active Expired - Fee Related
• 2014
  • 2014-10-14 EP EP14784222.3A patent/EP3058167B1/de active Active
  • 2014-10-14 BR BR112016008277-0A patent/BR112016008277B1/pt active IP Right Grant
  • 2014-10-14 WO PCT/EP2014/072006 patent/WO2015055645A1/fr not_active Ceased
  • 2014-10-14 DK DK14784222.3T patent/DK3058167T3/da active
  • 2014-10-14 CA CA2927242A patent/CA2927242C/fr active Active
  • 2014-10-14 AR ARP140103808A patent/AR098012A1/es unknown
  • 2014-10-14 US US15/029,172 patent/US10030488B2/en active Active
  • 2014-10-14 NO NO14784222A patent/NO3058167T3/no unknown

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