EP1046780B1 - Method of enhanced hydrocarbon production by injection of a liquid and gaseous phase at least partially miscible with water - Google Patents

Method of enhanced hydrocarbon production by injection of a liquid and gaseous phase at least partially miscible with water Download PDF

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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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gas
characterised
fact
process
described
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German (de)
French (fr)
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EP1046780A1 (en
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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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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/20Displacing by water
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164Injecting CO2 or carbonated water

Description

  • 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.
  • PRIOR ART
  • There are many processes of so-called secondary or tertiary primary type for recovering hydrocarbons in deposits, an example is described in US Patent 4,763,730.
  • 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. To do this, 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. Water is frequently used as a displacement fluid. However, its effectiveness is limited. A large part of the oil remains in place because its viscosity is greater than that of water. In addition, the oil remains trapped in the pore shrinkage of the formation due to the large difference in interfacial tension between it and the water. Finally, 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.
  • It is also known to combine water and gas injections according to a so-called WAG method for "Water Alternate Gas". According to this method, water and gas are injected successively as long as the fluids oil tankers are produced under economic conditions. The role of water plugs is to reduce the mobility of the gas and increase the swept area. Many improvements of this technique are proposed: the addition of surfactants to water in order to decrease the water-oil interfacial tension, the addition of foaming agent in water: the foam formed in the presence of gas will reduce significant mobility of the latter. Such a method is for example described in US Patent No. 3,893,511. By 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. By 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.
  • These secondary recovery techniques lead to recovery rates of 25 to 50% of the oil initially in place.
  • The objective of tertiary recovery is to improve this recovery rate, when residual oil saturation is reached. Under this name is grouped the injection into the tank of miscible gas, microemulsion, or steam or combustion in situ.
  • The definition of these primary, secondary and tertiary recovery techniques as their chronological application when a reservoir is put into production, dates back a few years. Pressure maintenance techniques are being implemented from the beginning of reservoir operation and the injection of fluids previously described as tertiary prior to a pronounced decline in the initial reservoir pressure.
  • More than 30% of hydrocarbon fields put into production contain acid compounds such as CO 2 and H 2 S. The exploitation of these fields requires the establishment of treatment processes to separate the recoverable gases from acid gases. The carbon dioxide from these facilities is frequently released into the atmosphere, increasing climate disturbances and the greenhouse effect. The management of hydrogen sulphide is problematic because of the high toxicity of this gas. It will usually be converted to solid sulfur by a Claus chain. This process requires a high investment that is not profitable at a time when global production of solid sulfur exceeds requirements. The reinjection of these acid gases into the deposit after complete or partial solubilization in an aqueous phase, which may be all or part of the production water, fresh water or brine from a water table, the sea water or other, has a dual interest: to get rid of low-cost acid gases without atmospheric pollutant discharge and increase the productivity of the reservoir.
  • DEFINITION OF THE INVENTION
  • The method for the assisted recovery of a petroleum fluid produced by a reservoir according to the invention 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.
  • According to one embodiment, 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.
  • To ensure that the gas is at least in saturation condition (and preferably supersaturation at the bottom of the well), it is preferable to use data produced from downhole state sensors (sensors). pressure, temperature sensors, etc., permanently installed) to control that the flushing gas gas is at least fully saturated
  • 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. These 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).
  • In another embodiment, 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.
  • According to another embodiment, 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. In the early stages of this circulation, 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. These two phenomena favor an increase in the recovery of hydrocarbons in place. When the fluid approaches the production wells, its pressure drops, under the combined effect of the flow losses due to the flow and the natural depletion of the deposit. If the pressure is less than the bubble pressure of the water containing the solubilized gas, bubbles of gas will form by nucleation in the pores of the rock mass, chasing the oil that is there towards the zones most permeable where it will be swept. This last phenomenon not only increases the overall recovery rate of the oil in place but decreases the time required to reach a given recovery rate.
  • 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. Preferably, the system comprises state sensors arranged in the injection zone for measuring thermodynamic parameters and connected to the control unit.
  • Other characteristics and advantages of the method according to the invention will appear on reading the following description of nonlimiting examples of implementation, with reference to the appended drawings in which:
    • Fig.1 shows a first embodiment of the method wherein the flushing fluid is formed downhole in the injection zone;
    • Fig.2 shows a second embodiment of the method wherein the sweeping fluid is formed on the surface; and
    • FIG. 3 shows an embodiment in which the gas in the sweeping fluid consists of acid fractions of gas from the subsoil or produced by chemical treatment units or thermal units burning various materials.
    Detailed description :
  • The recovery process which is the subject of the present invention comprises four steps:
  • 1. The preparation of the sweeping fluid.
  • Although this is not limiting, preferably readily available non-upgraded gases such as CO 2 carbon dioxide or hydrogen sulfide are preferably used. SH 2 .
  • The carbon dioxide mixed with the aqueous phase (hereinafter referred to as water) reacts according to the equilibrium reaction:

    CO 2 + H 2 OH 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. In the pressure and temperature range encountered for injection applications, typically a pressure ranging from 7.5 · 10 6 Pa to 30 · 10 6 Pa (75 to 300 bar) and a temperature ranging from 50 to 100 ° C, the effect of pressure is preponderant. In other words, 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.
  • At pressures below 10 · 10 6 Pa (100 bar), CO 2 dissolves less in salt water than in pure water. At a higher pressure, salinity affects much less the solubility of the gas. In pure water, under a pressure of 150 bars (15 MPa) and at a temperature of 70 ° C., the solubility of CO 2 will be about 4.5% by weight (45 kg of CO 2 are dissolved in 1 m 3 of water). The dissolution of the acid gas in the water leads to an increase in its viscosity, which improves the water / oil mobility ratio. The dissolution rate of hydrogen sulfide in water is approximately 2-fold higher than that of carbon dioxide, regardless of the temperature, pressure and composition of the aqueous phase. For example, under a pressure of 15 · 10 6 Pa (150 bar) and at a temperature of 70 ° C, 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.
  • 2. Injecting the sweeping fluid
  • An important point which makes the process according to the invention particularly effective in the scanning of a deposit is that the 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.
  • In order for this condition of saturation or supersaturation at the bottom of the well to be observed at all times, an injection system that can be disposed entirely on the surface or also include elements at the bottom of the well is used.
  • According to the embodiment shown diagrammatically in FIG. 1, 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.
  • According to a preferred embodiment, 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. In order to obtain the saturation and preferably supersaturation condition at the bottom of the well, it is necessary that 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.
  • For this purpose, it is possible to use (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. In this case, the acid gases are compressed in a compressor 1 in successive steps and cooled between two compression sections. In parallel, 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.
  • It is also possible to introduce an additional pressure drop in the injection line in the form of a rolling valve or a restriction of the injection conduit. According to a particular mode of implementation, a packing is also placed in the injection well IW to improve the mixing of the constituents while inducing an additional pressure drop. Preferably, 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.
  • According to the embodiment shown diagrammatically in FIG. 3, 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. . These 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.
  • If 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.
  • It is also possible that 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.
  • Preferably, a small proportion of surfactant promoting the dispersion of the gas bubbles is added to the aqueous phase. To reduce the excess of gas with respect to the saturation conditions prevailing at the surface, it is advantageous to increase the solubility of carbon dioxide in water by adding in the latter additives that promote its dissolution, such as monoethanolamine, diethanolamine, ammonia, carbonate of sodium, potassium carbonate, sodium or potassium hydroxide, potassium phosphates, diaminoisopropanol, methyl diethanol amine, triethanol amine and other weak bases. The concentration of these additives in water can vary from 10 to 30% by weight. It is verified that a solubility agent such as mono- ethanol amine added to water in the proportion of 15% by weight increases, for example by a factor of 7, the solubility of CO 2 in water. 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.
  • 3. Tank sweeping
  • 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.
  • It is also known that carbonated water prevents the swelling of clays frequently present in petroleum reservoirs. This effect is particularly noticeable for clays whose base ion is sodium. Calcium dissolution also influences the stabilization of sodium ion clays by the replacement of sodium with calcium which results in more stable clays resistant to flow without disintegrating and clogging the porous medium.
  • 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. At the same time, the water / oil mobility ratio is improved by decreasing the oil / water viscosity ratio. These facts help to significantly improve the efficiency of oil scavenging by water.
  • 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 carbon dioxide in the oil causes a significant increase in its volume. For the same rate of dissolution of carbon dioxide, this phenomenon will be more sensitive for light oils than for heavy oils.
  • 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. By way of example, 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 . Under identical conditions 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. In the porous medium, the pressure of the injected fluid will drop due to flow-related head losses. When the pressure will be lower than the bubble pressure of the water containing the solubilized gas, 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).
  • When these tanks are subjected to a water injection as part of the improved recovery of petroleum effluents, the water will preferentially invade the cracks. The water will then tend to soak the low permeability blocks by driving oil trapped in the pores to the network of cracks. If the tank is wettable with water, the imbibition will be under the effect of capillary forces and gravity. If the tank is wettable with oil, only the gravity will favor the phenomenon of imbibition.
  • When carbonated water is injected into the cracked medium, in the case of a water-wettable tank, the displacement of the oil by imbibition in blocks of low porosity is followed by the expansion of the carbon dioxide when the pressure will be lower than the bubble pressure of the carbonated water. The development of trapped gas bubbles in the low permeability massifs induces significantly increased oil recovery.
  • In the case of a reservoir of low wettability intermediate water or oil wettable, the phenomenon of imbibition by water will be less effective, the capillary forces not being favorable to the displacement of the oil by the water. The carbon dioxide released during depletion very advantageously replaces the water and invades the matrix blocks.
  • 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.
  • 4. Production
  • Over time, 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.
  • At equal temperature, it was verified that an increasing concentration of CO 2 in the carbonated water, induced a strong increase in the recovery of the oil in place. This increase is very noticeable when the flushing fluid is supersaturated with gas.

Claims (19)

  1. Process for assisted recovery of a petroleum fluid produced by a deposit, including the continuous injection into the deposit, through an injection well (IW), of a displacement fluid consisting of water to which gas at least partially miscible with an aqueous phase and with the petroleum fluid has been added, characterised by the fact that it includes continuous control at the injection well head of the ratio of the flow-rates of the aqueous phase and of gas forming the displacement fluid, so that the gas therein is in a saturated or super-saturated state at the injection well bottom.
  2. Process as described in claim 1, characterised by the fact that the displacement fluid is formed by mixture of the gas with the aqueous phase at the well bottom.
  3. Process as described in claim 1, characterised by the fact that the displacement fluid is formed by mixture of the gas with the aqueous phase at the well head.
  4. Process as described in one of claims 2 or 3, characterised by the fact that a control means arranged in the well is used to increase the degree of dissolution of the gas in the aqueous phase.
  5. Process as described in one of claims 1 to 4, characterised by the fact that it includes the use of a packing located in the injection well in order to intimately mix the gas and the aqueous phase of the displacement fluid.
  6. Process as described in one of claims 1 to 5, characterised by the fact that it includes the use of a polyphase pump to form an intimate mixture between the aqueous phase and gas and inject it into the injection well.
  7. Process as described in one of claims 1 to 6, characterised by the fact that it includes the use of data from well bottom state sensors to monitor that the gas of the displacement fluid is at least in a saturated state.
  8. Process as described in one of the preceding claims, characterised by the fact that the gas in the displacement fluid contains at least one acidic gas such as carbon dioxide and/or hydrogen sulphide.
  9. Process as described in one of the preceding claims, characterised by the fact that it includes the use of a treatment device suitable to extract at least a part of the gas in the displacement fluid from the effluents from a deposit.
  10. Process as described in one of the preceding claims, characterised by the fact that it includes the use of gaseous effluents from chemical or thermal units to form at least a part of the gas in the displacement fluid.
  11. Process as described in one of the preceding claims, characterised by the fact that water is used from a subsurface deposit to inject perhaps all or part of an aqueous phase associated with hydrocarbon production.
  12. Process as described in one of the preceding claims, characterised by the fact that a surfactant additive is added to the aqueous phase to favour the dispersion of the gas in it.
  13. Process as described in one of the preceding claims, characterised by the fact that at least one additive is added to the aqueous phase to increase the solubility of the gas in the displacement fluid.
  14. Process as described in one of the preceding claims, characterised by the fact that the injection of carbonated water is performed in wells with large offset, horizontal wells, or wells with complex geometry.
  15. Process as described in claim 14, characterised by the fact that the injection of the displacement fluid is performed in at least one well with large offset, horizontal well, or well with complex geometry located at the bottom of the deposit.
  16. Process as described in one of claims 1 to 14, characterised by the fact that the recovery of the petroleum fluid is effected in at least one directional well or well with complex geometry.
  17. Process as described in claim 16, characterised by the fact that each directional well or well with complex geometry is located at the top of the deposit.
  18. System for assisted recovery of a petroleum fluid extracted from a deposit, by continuous injection into the deposit of a displacement fluid formed of an aqueous phase to which has been added gas at least partially miscible with this aqueous phase and with the petroleum fluid, including an assembly for processing (PA) the displacement fluid and a unit (6) for continuous control of the processing assembly suitable to control the ratio of the flow-rates of the aqueous phase and of gas forming the displacement fluid reaching the well bottom, so that the gas therein is in a saturated or super-saturated state.
  19. Assisted recovery system as described in claim 18, characterised by the fact that it includes state sensors arranged in the injection zone to measure thermodynamic parameters and connected to the control unit (6).
EP00400945A 1999-04-23 2000-04-06 Method of enhanced hydrocarbon production by injection of a liquid and gaseous phase at least partially miscible with water Expired - Fee Related EP1046780B1 (en)

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FR9905584A FR2792678B1 (en) 1999-04-23 1999-04-23 Process for assisted recovery of hydrocarbons by combined injection of an aqueous phase and gas at least partially miscible with water
FR9905584 1999-04-23

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

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US6325147B1 (en) 2001-12-04
FR2792678A1 (en) 2000-10-27
CA2305946A1 (en) 2000-10-23
DK1046780T3 (en) 2006-04-10
FR2792678B1 (en) 2001-06-15
EP1046780A1 (en) 2000-10-25
NO20002029L (en) 2000-10-24
NO20002029D0 (en) 2000-04-18

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