EP1046780B1 - Procédé de récupération assistée d'hydrocarbures par injection combinée d'une phase aqueuse et de gaz au moins partiellement miscible à l'eau - Google Patents

Procédé de récupération assistée d'hydrocarbures par injection combinée d'une phase aqueuse et de gaz au moins partiellement miscible à l'eau Download PDF

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Publication number
EP1046780B1
EP1046780B1 EP00400945A EP00400945A EP1046780B1 EP 1046780 B1 EP1046780 B1 EP 1046780B1 EP 00400945 A EP00400945 A EP 00400945A EP 00400945 A EP00400945 A EP 00400945A EP 1046780 B1 EP1046780 B1 EP 1046780B1
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Prior art keywords
gas
fact
well
injection
aqueous phase
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EP00400945A
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German (de)
English (en)
French (fr)
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EP1046780A1 (fr
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Nicole Doerler
Gérard Renard
Alexandre Rojey
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IFP Energies Nouvelles IFPEN
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IFP Energies Nouvelles IFPEN
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    • 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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/20—Displacing by water
    • 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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164—Injecting CO2 or carbonated water

Definitions

  • the present invention relates to a method of assisted hydrocarbon recovery by combined injection of water and gas in a deposit.
  • the method according to the invention finds applications in particular to improve the movement of petroleum fluids to producing wells and thus increase the recovery rate of recoverable fluids, oil and gas, initially in place in the rock mass.
  • Recovery is called primary when petroleum fluids are produced under the sole action of the energy present in situ. This energy can result from the expansion of pressurized fluids in the deposit: expansion of the gas-saturated or non-saturated oil, expansion of a gas cap above the oil deposit, or a body of water active. During this phase, if the pressure in the deposit drops below the bubble point of the oil, the gaseous phase from the oil will help to increase the recovery rate. Recovery by natural drainage rarely exceeds 20% of fluids initially in place for light oils and is often below this value for heavy oil deposits.
  • Secondary recovery methods are used to avoid excessive pressure drop in the deposit.
  • the principle of these methods consists in bringing to the deposit an external energy.
  • fluids are injected into the deposit by one or more injection wells in order to move the recoverable petroleum fluids (hereinafter referred to as "oil") to production wells.
  • Oil is frequently used as a displacement fluid.
  • its effectiveness is limited. A large part of the oil remains in place because its viscosity is greater than that of water.
  • the oil remains trapped in the pore shrinkage of the formation due to the large difference in interfacial tension between it and the water.
  • the rock mass is frequently heterogeneous. In this context, the injected water will take the paths of greater permeabilities to reach the producing wells, leaving large unbrushed oil masses. These phenomena induce a significant loss of recovery.
  • Pressurized gas can also be injected into a reservoir for secondary recovery purposes, the gas has the well-known property of displacing significant amounts of oil. However, if the formation is heterogeneous, since the gas is much less viscous than the oil and the water in place, it will cross the rock mass by borrowing only some most permeable channels and will arrive quickly at the producing wells without having the expected displacement effect.
  • patent FR 2,735,524 of the applicant there is also known an improved method of adding to at least one of the water plugs injected alternately an agent decreasing the interfacial tension between water and gas. Under the effect of this agent, alcohol, for example, the oil can not spread over the water film covering the rock mass. The oil remains in the form of droplets that slow down the movement of the gas.
  • patent FR 2 764 632 of the applicant there is also known a method comprising the alternating injection of gas plugs and water plugs in which at least one of the water plugs is added gas under pressure both soluble in water and in oil. The production stage involves the relaxation of the pressure in the deposit, so as to generate gas bubbles that will drive hydrocarbons from the pores of the rock mass.
  • tertiary recovery is to improve this recovery rate, when residual oil saturation is reached.
  • This name is grouped the injection into the tank of miscible gas, microemulsion, or steam or combustion in situ.
  • the method for the assisted recovery of a petroleum fluid produced by a reservoir aims, by a combined injection of an aqueous phase and of gas coming from an external source or, as far as possible, at least in part from acid gases from the effluents from the deposit itself, to increase the recovery rate of hydrocarbons.
  • the method comprises the continuous injection by an injection well of a sweeping fluid consisting of an aqueous phase containing gas at least partially miscible in water and in the petroleum fluid, with a permanent control at the wellhead. injection, the ratio of flow rates of this aqueous phase and gas forming the sweep fluid so that, at the bottom of the injection well, the gas is in saturation or supersaturation state.
  • the sweeping fluid may be formed either at the bottom of the well with separate conveyance of the constituents to the injection zone, or at the wellhead.
  • a means disposed in the injection well may be used to create a pressure drop such as a valve or conduit restriction and thereby increase the dissolution rate of the gas in the water.
  • a packing placed in the injection well to intimately mix the gas and the aqueous phase of the sweep fluid also increases the pressure drop and the dissolution rate.
  • a multiphase pump of rotodynamic type is used, for example to compress the gas, pressurize the aqueous phase and form an intimate mixture between this aqueous phase and pressurized gas before injecting it into the well. 'injection.
  • the gas in the flushing fluid contains at least one acid gas such as carbon dioxide and / or hydrogen sulfide and optionally, in varying proportions, other gases: methane, nitrogen, etc.
  • acid gas such as carbon dioxide and / or hydrogen sulfide
  • gases can be taken from the effluents from a deposit, an operation carried out by a treatment unit adapted to separate them from other gases that can be recovered elsewhere, or from chemical units or thermal units burning lignite, coal, oil, natural gas etc.
  • the aqueous phase used to form the sweeping fluid may be, for example, water from an underground deposit (for example a groundwater table or a brine produced during the exploitation of a deposit) or any other readily available water ( sea water).
  • an underground deposit for example a groundwater table or a brine produced during the exploitation of a deposit
  • any other readily available water sea water
  • a surfactant additive is added to the aqueous phase to promote the dispersion of the gas and / or one or more additives to increase the solubility of the gas in the sweeping fluid.
  • the sweeping fluid is injected for example into one or more high offset wells, horizontal or of complex geometry located for example at the base of the deposit and the petroleum fluid is produced for example by one or several deflected wells or complex geometry can be located at the roof of the deposit.
  • the process can be implemented from the beginning of the exploitation of the deposit.
  • the aqueous phase injected preferentially at the periphery of the producing zone, sweeps the porous medium containing the hydrocarbons at recover.
  • carbon dioxide much more soluble in oil than in injected water, passes from the sweep fluid to the petroleum fluid causing its swelling and decreasing its viscosity.
  • the invention also relates to a system for assisted recovery of a petroleum fluid extracted from a reservoir, by continuous injection into the reservoir of a flushing fluid consisting of an aqueous phase with added gas at least partially miscible in the aqueous phase and in the petroleum fluid, which comprises a conditioning assembly of the sweeping fluid and a permanent control unit of the conditioning assembly adapted to control the ratio of the flow rates of this aqueous phase and of the gas forming the bottom flushing fluid. wells, so that the gas is in saturation or supersaturation.
  • the system comprises state sensors arranged in the injection zone for measuring thermodynamic parameters and connected to the control unit.
  • the recovery process which is the subject of the present invention comprises four steps:
  • non-upgraded gases such as CO 2 carbon dioxide or hydrogen sulfide are preferably used.
  • SH 2 preferably readily available non-upgraded gases such as CO 2 carbon dioxide or hydrogen sulfide are preferably used.
  • the carbon dioxide mixed with the aqueous phase reacts according to the equilibrium reaction: CO 2 + H 2 O ⁇ H 2 CO 3 giving carbonic acid.
  • the solubility of carbon dioxide in water depends on the salinity of the water, the temperature and the pressure.
  • the dissolution rate of CO 2 increases with the pressure and decreases with temperature.
  • the effect of pressure is preponderant.
  • the dissolution rate of the carbon dioxide at the bottom of an injection well is greater than the rate of dissolution at the surface, despite the temperature increase due to the geothermal gradient.
  • the solubility of the H 2 S will be about 8.3% by weight (83 kg H 2 S are dissolved in 1 m 3 of water).
  • the acid gases from oil production mainly contain carbon dioxide, it is the solubility of this gas that will be limiting when the mixture will be dissolved in an aqueous fluid.
  • flushing fluid is injected such that at the bottom of the well, in the injection zone, the solution injected water is at least saturated and preferably supersaturated with gas.
  • the volumes of acid gases and water that can be reinjected into the deposit can be available in a ratio much higher than the ratio of solubility of the acid gas in water. This ratio may change during the course of the operation or according to the constraints of production.
  • the increase in pressure at the bottom of the injection well is partially compensated by an increase in the temperature linked to the geothermal gradient. However, the effect of the pressure is generally greater, especially since the injected fluid does not reach the conditions of thermal equilibrium.
  • an injection system that can be disposed entirely on the surface or also include elements at the bottom of the well is used.
  • the sweeping fluid is produced by a packaging unit PA and its constituents, brought separately into the injection zone at the bottom of the well.
  • the gas is compressed by a compressor 1 and injected by an injection tube 2 to the bottom of the injection well IW, while the water from a pump 3 is injected into the annular space 4 between the casing and the injection tube 1.
  • the mixing between the two phases takes place under the seal 5 to the right of the injection zone.
  • the injection pressures of the compressor 1 and the pump 3 are determined by a control device 6.
  • the injection of gas requiring a high pressure at the wellhead it is preferred to perform the mixture on the surface before injecting it.
  • This simultaneous injection makes it possible to increase the weight of the liquid column in the injection well, and to reduce substantially the necessary gas pressure.
  • the mixture produced at the well head be highly supersaturated with acid gases and be particularly homogeneous, the gas being dispersed in the liquid phase.
  • FIG. 2 a conventional compression and pumping device known to those skilled in the art, for the injection of the sweep fluid under a saturation or supersaturation condition downhole.
  • the acid gases are compressed in a compressor 1 in successive steps and cooled between two compression sections.
  • the water is pressurized by a pump 3 at a pressure equal to that applied by the compressor 1.
  • the gas and the liquid are then introduced into a static or dynamic mixer 7 having a sufficient efficiency to allow the total dispersion of the gas in the liquid. Downstream of the mixer 7, the mixture can be compressed by an additional pump 8 to allow either the dissolution of an additional amount of gas or the injection of the flushing fluid into the well IW.
  • the acid gases, heated during the compression may for example be cooled by means of heat exchangers (not shown) before their introduction into the mixer 7 so as to promote their dissolution.
  • a rotodynamic type multiphase pump can advantageously replace a conventional reinjection chain and fulfill the three functions of compressing the gas, pressurizing the liquid phase and mixing intimately the two phases.
  • a rotodynamic multiphase pump suitable for this type of application is described in patents FR 2,665,224 (US 5,375,976) to the applicant or FR 2,771,024 to the applicant. By design, this type of pump can inject into a well a two-phase mixture composed of saturated carbonated water and an excess of gaseous carbon dioxide without cavitation problem.
  • a packing is also placed in the injection well IW to improve the mixing of the constituents while inducing an additional pressure drop.
  • a packing is also placed in the injection well IW to improve the mixing of the constituents while inducing an additional pressure drop.
  • it is used in the one and the another case of state sensors (not shown) down to the well bottom, in the injection zone, for measuring various thermodynamic parameters: pressures, temperatures, etc., and connected to the control device 6.
  • a transmission system adapted to transmit on the surface signals from permanent sensors permanently installed in wells for monitoring a deposit, and in particular state sensors making it possible to know, for example, the temperatures and pressures at the bottom of the well, is described in particular in the patent US 5,363,094 of the applicant.
  • the control device 6 adjusts the flow rates and their ratio in this case according to the conditions prevailing in situ.
  • the system is adapted to form a saturated or supersaturated mixture, at least in part, by controlled recombination of effluents pumped out of the deposit by one or more production wells of the PW deposit.
  • effluents include generally a liquid phase consisting of water and oil, and a gaseous phase.
  • the effluents therefore pass into a water-oil-gas separator S1.
  • the gaseous phase possibly supplemented by external inputs, passes through a separator S2 for separating the otherwise recoverable gases for other applications, acid gases that we want to recycle.
  • the water issuing from the separator S1 is then recombined with the acid gases recovered in a controlled mixing device M, so as to form the saturated or supersaturated mixture under the conditions prevailing at the bottom of the well.
  • the pressure necessary to inject the fluid into the porous mass is lower than the CO 2 liquefaction pressure, a liquid phase and a gaseous phase will be present in the injection well.
  • the user must ensure that the dispersion of the gas is maximum and that the gas plugs circulating in the injection well are driven by the liquid column at the bottom of the well, in other words that the liquid velocity is greater than the rate of rise of the gaseous plugs to avoid segregation in the injection well.
  • the pressure necessary to inject the fluid into the porous mass is greater than the CO 2 liquefaction pressure.
  • the liquefied gas will be intimately mixed with the water and an emulsion formed of fine droplets of liquefied gas in the water will then be injected.
  • a small proportion of surfactant promoting the dispersion of the gas bubbles is added to the aqueous phase.
  • the concentration of these additives in water can vary from 10 to 30% by weight.
  • the injection wells can be vertical or horizontal wells. Generally, if the tank is thin, it may be advantageous to implement the injection of carbonated water in wells of high offset or in horizontal wells.
  • the aqueous phase can be injected at the base of the reservoir to be drained by means of one or more horizontal wells and the liquid hydrocarbon phase can be withdrawn from the roof of the tank by means of one or more horizontal wells. For thick tanks the injection and production wells will be vertical, and the hydrocarbon sweep in place will be parallel to the reservoir boundaries. Wells of more complex geometry can be used without departing from the scope of the present invention.
  • the recovery principle according to the invention makes it possible to supply the deposit with additional energy.
  • the benefits of simultaneous injection of water and acid gases are numerous.
  • Carbonated water solubilizes the soluble carbonates present in the rock, calcite and dolomite, forming soluble bicarbonates according to the reactions: Ca CO 3 + H 2 CO 3 ⁇ Ca (HCO 3 ) 2 Mg CO 3 + H 2 CO 3 ⁇ Mg (HCO 3 ) 2
  • This partial dissolution of the carbonates causes an increase in the permeability of the porous medium, whether it is a sandstone, in which the dissolution will attack the cements and calcium deposits frequently present around the quartz grains, or a formation limestone in which the porous connection will be improved.
  • the permeability gain resulting from the dissolution of the carbonates can be significant, as is well known in the art.
  • the viscosity of the water increases when the CO 2 dissolves there.
  • the volume of this carbonated water increases by 2 to 7% depending on the concentration of dissolved gas and its density decreases slightly.
  • the overall effect of decreasing the density contrast between water and oil reduces the risks of segregation by gravity.
  • the water / oil mobility ratio is improved by decreasing the oil / water viscosity ratio.
  • Carbon dioxide is much less soluble in water than in oil fields. This solubility is a function of the pressure, the temperature and characteristics of the oil. Under certain conditions, carbon dioxide can be partially or completely miscible with hydrocarbons. When it is injected into the deposit in the form of carbonated water, the carbon dioxide will preferentially go from water to oil.
  • the dissolution of the carbon dioxide in the oil also causes a decrease in its viscosity. This decrease will be greater when the amount of CO 2 increases.
  • An oil having initially a high viscosity will be more sensitive to the phenomenon.
  • a density oil 12.2 API (0.99 g / cm 3 ) and having a viscosity of 900 mPa.s at ambient pressure and a temperature of 65 ° C will reduce its viscosity to 40 mPa.s under a pressure 150 bars of CO 2 .
  • a viscosity of an API density oil (0.93 g / cm 3 ) will drop from 6 to 0.5 mPa ⁇ s.
  • the swelling of the oil as the drop in its viscosity promotes an increase in the recovery of hydrocarbons initially in place in the deposit. They also help speed up the process of oil recovery.
  • the carbonated water is at least saturated with CO 2 when it is injected into the reservoir.
  • the pressure of the injected fluid will drop due to flow-related head losses.
  • gas will be released.
  • the nucleation of the carbon dioxide bubbles will preferably occur on contact with the rock and specifically in areas with a high concentration of rock / liquid interfaces. These zones correspond to low permeability massifs; magnification and migration of gas bubbles will drive oil trapped in the small diameter pores of the rock. This phenomenon significantly increases the rate of hydrocarbons mobilized during production.
  • the recovery process as described above finds an advantageous application during the production of deposit with a dual porosity system such as cracked deposits.
  • a simple representation of these deposits is a set of rock blocks of decimetric or metric size with pores of small diameters and saturated with oil, interconnected by a network of cracks offering a passage to the flow of the fluids of a few tens of micrometers on average.
  • Two types of cracked reservoirs can typically be distinguished: tanks with water-wettable rock, and intermediate wettable or oil wettable tanks (eg, some carbonate rock masses).
  • the exploitation of the deposit may include injection and depletion cycles. During the injection period, production will be stopped or decreased while the injection of carbonated water will be maintained, in order to raise the pressure in the reservoir beyond the bubble pressure of the water and thereby increase the concentration of available carbon dioxide. This injection period will be followed by a period of production and partial depletion of the deposit.
  • the hydrocarbons produced have increasing concentrations of acid gases. As we have seen above, these gases are advantageously separated from the gas that can be valorized elsewhere and reinjected into the deposit. If the gas treatment and refining units are close to producing wells, the gas and the oil will be separated by successive expansion in separation balloons S1, S2 (Fig.3) located near the production area. If the refinery unit of a heavy crude is removed from the production area, it is possible to transport under pressure the crude charged with its gas. The CO 2 which substantially reduces the viscosity of the heavy oil advantageously replaces a fluxing agent.
  • Comparative tests were conducted in the laboratory on oil-impregnated rock cores selected and adapted to represent a cracked reservoir. They have been placed in a containment cell associated with a pressurized fluid circulation system, of the same type for example as those described by patents FR 2,708,742 (US 5,679,885) or FR 2,731,073 (US 5,679,885) to the applicant. and subjected to various sweep tests by a gas phase under the gas saturation or supersaturation conditions set forth above. These tests have demonstrated the effectiveness of the process according to the present invention.

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  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
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  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Gas Separation By Absorption (AREA)
  • Physical Or Chemical Processes And Apparatus (AREA)
EP00400945A 1999-04-23 2000-04-06 Procédé de récupération assistée d'hydrocarbures par injection combinée d'une phase aqueuse et de gaz au moins partiellement miscible à l'eau Expired - Lifetime EP1046780B1 (fr)

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FR9905584A FR2792678B1 (fr) 1999-04-23 1999-04-23 Procede de recuperation assistee d'hydrocarbures par injection combinee d'une phase aqueuse et de gaz au moins partiellement miscible a l'eau
FR9905584 1999-04-23

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EP1046780A1 EP1046780A1 (fr) 2000-10-25
EP1046780B1 true EP1046780B1 (fr) 2006-02-08

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US (1) US6325147B1 (no)
EP (1) EP1046780B1 (no)
CA (1) CA2305946A1 (no)
DK (1) DK1046780T3 (no)
FR (1) FR2792678B1 (no)
NO (1) NO20002029L (no)

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DK1046780T3 (da) 2006-04-10
FR2792678B1 (fr) 2001-06-15
CA2305946A1 (fr) 2000-10-23
FR2792678A1 (fr) 2000-10-27
NO20002029D0 (no) 2000-04-18
NO20002029L (no) 2000-10-24
US6325147B1 (en) 2001-12-04

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