WO2015022288A2 - Method for extracting petroleum from a subterranean petroleum deposit having inhomogeneous permeability - Google Patents

Abstract

The invention relates to a method for extracting petroleum from a subterranean petroleum deposit, comprising the following steps: a) drilling at least one injection borehole (IB) and at least two production boreholes (PB) into the subterranean petroleum deposit; b) injecting a fracturing agent (FM) through the at least one injection borehole (IB) into the subterranean petroleum deposit and removal of petroleum from the at least two production boreholes (PB), wherein a highly permeable zone (1) in the subterranean petroleum deposit is formed in the near vicinity of the at least one injection borehole (IB); c) ceasing to inject the fracturing agent (FM) through the at least one injection borehole (IB); d) blocking the highly permeable zone (1) in the near vicinity of the at least one injection borehole (IB); e) injecting a fracturing agent (FM) through at least one new injection borehole (nIB) into the subterranean petroleum deposit and removing petroleum from at least one production borehole (PB).

Description

 Process for extracting oil from a subterranean mineral oil deposit with inhomogeneous permeability

description

The present invention relates to a method of extracting petroleum from an inhomogeneous permeable subterranean oil deposit into which at least one injection well (IB) and at least two production wells (PB) have been sunk.

In natural petroleum reservoirs, petroleum is generally present in the voids of porous reservoirs which are closed to the earth's surface by impermeable facings. In addition to crude oil and natural gas, underground oil reservoirs generally contain more or less saline water. The water that is present in the underground oil deposits is also referred to as reservoir water or formation water. In the cavities in which the petroleum is present, it may be very fine cavities, capillaries, pores or the like. The cavities may for example have a diameter of only one micrometer.

In the case of oil production, a distinction is made between primary, secondary and tertiary production. In primary production, after sinking the well into the subterranean deposit, the petroleum automatically streams to the surface through the borehole due to the inherent natural pressure of the oil reservoir. The autogenous pressure of the oil reservoir can be caused, for example, by gases present in the reservoir, such as methane, ethane or propane. Depending on the type of deposit, primary oil production can usually only produce 5 to 10% of the oil in the deposit. Thereafter, the autogenous pressure of the oil reservoir is no longer sufficient to recover oil from the underground oil reservoir by the primary oil production.

After primary oil production, therefore, secondary and tertiary mineral oil production is used. In secondary and tertiary oil production, additional drilling will be drilled (drilled) in the oil reservoir. A distinction is generally made between so-called production wells (PB) and so-called injection wells (IB). Production wells (PB) are used to extract petroleum from the underground oil reservoir to the surface. The injection wells (IB) inject a flood medium (FM) into the oil reservoir to maintain or increase the pressure of the underground oil reservoir. By injecting the flooding agent (FM), the oil is slowly from the injection well through the cavities of the underground Erdöllagerstätte (IB), starting in the direction of the production wells (PB). As a result, the oil from the underground Erdöllagerstätte in the production wells (PB) and is conveyed to the surface, for example by means of pumps. However, these methods of secondary or tertiary mineral oil production only works as long as the cavities of the underground oil reservoir are completely filled with petroleum and, compared to the flood medium (FM), displaces viscous petroleum through the flood medium (FM) injected through the injection well (IB) becomes.

As a rule, only about 30 to 35% of the total amount of crude oil in the oil reservoir can be recovered from primary and secondary oil production methods. As flooding agent (FM), water is generally used in secondary crude oil production. This process is also known as water flooding.

Measures are described in the prior art to further increase the production from underground oil deposits after completion of the secondary oil production. These measures are also referred to as tertiary oil production. Tertiary oil production includes, for example, heat processes in which hot water or superheated steam is injected into the crude oil deposit. As a result, the viscosity of the petroleum is reduced. In addition, gases such as carbon dioxide or nitrogen can be used as flooding agent (FM) for tertiary mineral oil production.

Tertiary oil production also includes processes in which the flux (FM) is added to suitable chemicals as an aid to mineral oil extraction. These can be used to influence the situation towards the end of secondary oil production, for example by flooding, and thus also to extract crude oil, which until then has been stored in the cavities in the underground oil reservoir.

At least one injection well (IB) as well as multiple production wells (PB) are generally drilled into the subterranean crude oil deposit in the secondary or tertiary petroleum production processes described in the prior art. Through the injection well (IB), as described above, a flooding agent (FM) is injected into the underground oil reservoir. The Flood Means (FM) displaces the oil in the underground oil reservoir to the production wells (PB) and is transported through them. Tertiary oil production processes can increase the yield of original oil in the reservoir (original oil in place or ooip) to> 50%.

The processes for secondary or tertiary mineral oil extraction form zones of different permeability in the underground oil reservoir. Subterranean oil deposits in which zones of different permeability have been formed by processes for secondary or tertiary mineral oil production, are also referred to as subterranean oil deposits with inhomogeneous permeability.

The state in an underground Erdöllagerstätte with inhomogeneous permeability after performing secondary or tertiary processes for oil production is exemplified in Figure 1. FIG. 1 shows a horizontal section (the top view) of an underground oil reservoir towards the end of the secondary or tertiary conveying methods. In the center there is an injection well (I B). Around this injection hole (I B), seven production holes (PB1 to PB7) are arranged. Due to the secondary or tertiary production methods, the underground oil reservoir has an inhomogeneous permeability.

The zones of underground oil reservoir from which the oil was displaced by the flood medium (FM) have a higher permeability than the zones in which there is still oil. The compounds (20 to 26) in Figure 1 are almost completely free of petroleum. The compounds (20 to 26) therefore have a very high permeability. Between the compounds (20 to 26) are zones in the underground oil reservoir, which still contain petroleum. These zones are indicated in Figure 1 by the reference numeral 1 1 to 15. These zones have a significantly higher permeability. The petroleum-containing zones (1 1 to 15) are also referred to as congestion zones.

Due to the lower permeability of the connections (20 to 26), the injection well (I B) to the production wells (PB1 to PB7) has a very good hydrodynamic communication. The injected flooding agent (FM) therefore flows from the injection well (I B) directly to the production wells (PB1 to PB7). A displacement of petroleum from the storage zones (1 1 to 15) is practically no longer taking place. From the production wells (PB1 to PB7) practically only flood medium (FM) is removed.

In the event that water is used as flooding agent (FM), this phenomenon is also referred to as water breakthrough or flooding. The compounds (20 to 26) are also referred to as waterways and flood routes. The flow direction of the flood medium (FM) is indicated by the arrows in FIG.

The state in which at least 50% by weight of water or flooding agent (FM), preferably at least 70% by weight and particularly preferably at least 80% by weight, is withdrawn from the production wells (PB), is the water breakthrough or flooding breakthrough , in each case based on the total weight of the fluids taken from the production wells (PB). The methods for secondary or tertiary mineral oil extraction form a highly permeable zone (1) in the vicinity of the injection well (IB). The highly permeable zone (1), like the compounds (20 to 26) completely freed of petroleum. Towards the end of the secondary or tertiary petroleum extraction methods, therefore, mainly flood medium (FM) is conveyed from the production bores PB1 to PB7 in FIG. A promotion of oil from the storage zones (1 1 to 15) is no longer possible with this method.

In order to mobilize the petroleum present in the stagnation zones (11 to 15), RU 2 217 582 describes a method in which the injection of the flood medium (FM) is shifted from the original injection well (IB) to a production well (PB) , This method is shown by way of example in FIG. For this purpose, the original injection well (I B) is closed. This can be done for example by the use of packers. The sealed injection well is also referred to as a terminated injection well and bears in Figure 2, the reference I Bt.

After closing the original injection well (I B), the injection of flooding agent (FM) continues through an initial production well (PB). In Figure 2, the new injection bore carries the reference numeral NIB. The new injection well (nI B) corresponds to the original production well (PB5). According to the method according to RU 2 217 582, it is also possible, as a new injection well (nI B), to drill down a further injection well (nI B) into the underground oil reservoir. This embodiment of the method according to RU 2 217 582 is shown by way of example in FIG. By the method according to RU 2 217 582, the flow direction of the flood medium (FM) in the underground oil reservoir changes. The flow direction of the flood medium (FM) is indicated in FIGS. 2 and 3 by arrows. The process according to RU 2 217 582 achieves a short-term increase in the production of crude oil from the underground oil reservoir.

A disadvantage of the method according to RU 2 217 582 is that the flooding agent (FM) injected through the new injection well (nI B) reaches the highly permeable zone (1) in the vicinity of the shut-down injection well (I Bt) after a short time. The highly permeable zone (1) is in good hydrodynamic communication with the original production wells PB1 to PB4 and PB6 and PB7 (see FIG. 2). The flooding agent (FM) therefore flows after a short time via the connections (20 to 26) to the production holes PB1 to PB4 and PB6 and PB7. Thus, in the method exemplarily illustrated in FIG. 2, after a short time, a water breakthrough or flood medium breakthrough is registered in the production wells (PB). In the method disclosed in RU 2 217 582, in which a new injection well (NIB) is drilled into the underground oil reservoir, the efficiency is slightly higher. Starting from the new injection well (nIB) in Figure 3, a flood front (2) is formed, through which a further displacement of petroleum is achieved in the underground Erdöllagerstätte. However, as soon as this flood front (2) reaches the production bore (PB5), the connection (24) or the highly permeable zone (1), the flood medium (FM) also flows unhindered to the production wells (PB1 to PB7) after a short time. Also in this method, a water or flooding breakthrough is thus registered after a short time.

The object of the present invention is thus to provide a process for the extraction of crude oil from an underground oil reservoir into which at least one injection well (IB) and several production wells (PB) have been drilled. In particular, the process is intended to increase the yield of petroleum towards the end of secondary or tertiary methods of producing oil, after a water or flood agent breakthrough has been registered. The process should allow effective mobilization of oil from congestion zones (1 1 to 15). In addition, the method should be simple and inexpensive to carry out and, ideally, manage without the costly sinking of further injection wells.

This object is achieved by a method for producing oil from an underground oil reservoir, comprising the following steps: a) Lowering at least one injection well (IB) and at least two production wells (PB) into the underground oil reservoir.

Injecting a flood medium (FM) through the at least one injection well (IB) into the subterranean oil reservoir and extracting oil from the at least two production wells (PB), with a highly permeable zone in the vicinity of the at least one injection well (IB) in the subterranean crude oil reservoir ( 1),

Adjusting the injection of the flood medium (FM) through the at least one injection well (IB),

Blocking the high permeability zone (1) in the vicinity of the at least one injection well (IB), e) injecting a flood medium (FM) through at least one new injection well (NIB) into the underground well deposit and extracting oil from at least one production well (PB). It has been found that the method according to the invention achieves an effective increase in the production rates of crude oil from a subterranean mineral oil deposit which has an inhomogeneous permeability due to secondary or tertiary mineral oil extraction methods. The method is simple and inexpensive to carry out. In addition, the method has the advantage that in a preferred embodiment it does not require the sinking (sinking) of further injection wells (IB). As a result, the method according to the invention is cost-efficient, since a further production of crude oil is made possible without the cost-intensive laying down of further boreholes in the subterranean crude oil deposit being necessary.

Process step a)

In process step a), at least one injection well (IB) and at least two production wells (PB) are drilled (sunk) into the subterranean crude oil deposit. The injection of the injection wells (IB) and the production wells into the underground oil reservoir can be carried out by conventional methods known to the person skilled in the art and is described, for example, in EP 0 952 300. The holes can be vertical, horizontal or deflected holes.

Subterranean oil deposits may be deposits for all grades of oil, such as those for light or heavy oil. The petroleum contained in the underground oil reservoir generally has a viscosity in the range of 3 to 10,000 mPa / s, measured at the temperature of the underground oil reservoir (T _L ). The temperature of the underground oil reservoir (T _L ) can also vary widely. It is generally in the range of 8 to 200 ° C, preferably in the range of 20 to 180 ° C, and more preferably in the range of 70 to 150 ° C.

Also, the depth of the injection well (IB) and the production wells (PB) is not essential to the process of the invention. The injection well (IB) and the production wells (PB) generally have a length in the range of 100 to 10,000 m, preferably in the range 100 to 4000 m, and more preferably in the range of 100 to 2000 m.

Process step b):

In step b), a flood medium (FM) is injected through the at least one injection well (IB) into the underground oil reservoir and oil is extracted from at least two production wells (PB). According to the invention, the term "at least one injection well (IB)" means both exactly one injection well (IB) and two or more injection wells (IB) The terms "at least one injection well (IB)" and "one injection well (IB)" used synonymously.

According to the invention, the term "at least two production wells (PB)" means both exactly two production wells (PB) and three or more production wells (PB) .The terms "at least two production wells (PB)" and "production wells (PB)" become synonymous second hand.

The number of injection wells (IB) depends on the type and nature of the underground oil reservoir and can vary widely. The number of injection wells (IB) is generally in the range of 1 to 20. The number of production wells (PB) can also vary widely. In general, according to the invention, in process step a), at least one production well (PB) is drilled more into the underground oil reservoir than injection wells (IB) are drilled. This means that in the event that only one injection well (IB) is drilled into the subterranean crude oil deposit, at least two production wells (PB) are drilled in the subterranean crude oil deposit in process step a). In reservoir development, one can speak of a cluster-like grouping of wells, typically including a cluster with an injection well (IB) and the production wells (PB) affected by this injection well (IB).

The subject matter of the present invention is therefore also a process in which, in process step a), at least one production well (PB) is drilled more into the subterranean crude oil deposit than injection wells (IB) are drilled.

A cluster will generally comprise a maximum of 15 to 20 holes (sum of injection holes (IB) and production holes (PB) affected by the injection hole (IB)). In other words, the cluster thus comprises the injection well (IB) and the production wells (PB, PB1 to PB7), from which petroleum is extracted in process step b).

In a preferred embodiment, in process step a) at least two production wells (PB) more, preferably at least three production wells (PB) more, more preferably at least four production wells (PB) more and more preferably at least five production wells (PB) drilled more in the underground Erdöllagerstätte , are drilled as injection wells (IB) into the underground oil reservoir. Subsequently, a flood medium (FM) is injected through the at least one injection well (IB) into the underground oil reservoir. As flooding agent (FM), all flooding agents (FM) known to those skilled in the art can be used in process step b). The type of flooding agent (FM) used in process step b) is not essential to the invention. In principle, all floods (FM) can be used, which are suitable for secondary or tertiary oil production. An aqueous flooding agent (wFM) is preferably used in process step b). As the aqueous flooding agent (wFM), water itself or water to which additives have been added can be used. The aqueous flooding agent (wFM) can have temperatures in the range of 0 ° C to 100 ° C. It is also possible to use aqueous flooding agents (wFM) in the form of steam. With the use of steam, a particularly large highly permeable zone (1) is formed, which has a much higher permeability compared to the original permeability of the underground oil reservoir. This is due to the aggressive effect of the superheated steam, which washes the oil particularly well.

In general, the aqueous flooding agent (wFM) contains at least 50% by weight, preferably at least 70% by weight, more preferably at least 80% by weight and most preferably at least 90% by weight of water. Accordingly, the aqueous flooding agent (wFM) may contain 0 to 50 wt%, preferably 0 to 30 wt%, more preferably 0 to 20 wt% and most preferably 0 to 10 wt% of other additives and natural salts ,

The percentages by weight are in each case based on the total weight of the aqueous flooding agent (wFM). Thickeners, surfactants, urea or glycerol, for example, can be used as further customary additives. Suitable thickeners are, for example, synthetic polymers such as polyacrylamide or copolymers of acrylamide and other monomers, especially monomers containing sulfonic acid groups, and polymers of natural origin such as glucosylglucans, xanthan, diuthane or glucan. Glucan is preferred.

As surface-active components (surfactants) it is possible to use anionic, cationic and nonionic surfactants.

Common nonionic surfactants are, for example, ethoxylated mono-, di- and trialkylphenols, ethoxylated fatty alcohols and polyalkylene oxides. In addition to the unmixed polyalkylene oxides, preferably C ₂ -C ₄ -alkylene oxides and phenyl-substituted C ₂ -C ₄ -alkylene oxides, in particular polyethylene oxides, Polypropylene oxides and poly (phenylethylene oxides), especially block copolymers, in particular polypropylene oxide and polyethylene oxide blocks or poly (phenylethylene oxide) and polyethylene oxide blocks having polymers, and also random copolymers of these alkylene oxides are suitable. Such Alkylenoxidblockcopolymerisate are known and commercially z. B. under the name Tetronice and Pluronic (BASF) available

Typical anionic surfactants are, for example, alkali metal and ammonium salts of alkyl sulfates (alkyl radical: C ₈ -C ₁₂ ), of sulfuric monoesters of ethoxylated alkanols (alkyl radical: C ₂ -C ₈ ) and ethoxylated alkylphenols (alkyl radicals: C 4 -C ₁₂ ) and of alkylsulfonic acids (alkyl radical: C ₁₂ -C ₁₈ ).

Suitable cationic surfactants are, for example, C ₆ -C ₁₈ -alkyl, alkylaryl or heterocyclic radicals, primary, secondary, tertiary or quaternary ammonium salts, pyridinium salts, imidazolinium salts, oxozolinium salts, morpholinium salts, propylium salts, sulfonium salts and phosphonium salts. Examples of its dodecylammonium acetate or the corresponding sulfate, disulfates or acetates of the various 2- (N, N, N-trimethylammonium) ethylparaffinsäure- esters, N-Cetylpyridiniumsulfat and N-Laurylpyridiniumsalze, cetyltrimethylammonium bromide and sodium lauryl sulfate called.

Injecting the flooding agent (FM) described above, preferably the aqueous flooding agent (wFM), through the at least one injection well (IB) into the subterranean crude oil deposit results in a highly permeable near-surface of the at least one injection well (IB) in the subterranean crude oil deposit Zone (1) by the action of flooding (FM) forms.

This is the result of the long-term effect of the flow of the flood medium (FM) on the underground oil reservoir and the deposits matrix, the effect in the vicinity of the injection well (IB) is maximum. In the event that, for example, an average of about 100 cm ³ of water per day through the injection well (IB) are injected flow through the vicinity of the injection well (IB) in the period of 5 years, about 175 000 m ³ of water. The state after execution of method step b) is shown by way of example in FIG. 1, which has already been described above. By injecting the flooding agent (FM) in addition to the highly permeable zone beyond the compounds (20 to 26). The compounds (20 to 26) also have a high permeability and are therefore also referred to as flood or water ways. Through the connections (20 to 26) the production wells (PB1 to PB7) are above the high permeability zone (1) with the injection well (IB) in hydrodynamic communication. In addition, the production wells (PB1 to PB7) through the compounds (20 to 26) via the highly permeable zone (1) with each other in hydrodynamic communication. By "in hydrodynamic communication" is meant according to the invention that liquids, preferably flooding agents (FM), can be exchanged through the compounds (20 to 26) via the highly permeable zone (1) between the bores of a cluster.

The subject matter of the present invention is thus also a method in which the underground subsurface oil deposit after method step b) has connections (20 to 26) through which the production bores (PB1 to PB7) communicate with one another and with the injection well (IB) via the highly permeable zone (FIG. 1) are in hydrodynamic communication.

For the highly permeable zone (1) and the connections (20 to 26) which have formed after method step b), the statements described at the outset with regard to FIG. 1 apply correspondingly. Between the compounds (20 to 26) are the congestion zones (1 1 to 15), which still contain petroleum.

According to the invention, "highly permeable zone (1)" means that this zone has a permeability which is at least 20%, preferably at least 50%, particularly preferably at least 75% and particularly preferably at least 90% higher than the permeability of the congestion zones (1 1 to 15) The permeability of the congestion zones (1 1 to 15) corresponds to the original permeability of the

25 underground Erdöllagerstätte, that is the permeability before carrying out the method according to the invention.

The subject matter of the present invention is therefore also a process in which the highly permeable zone (1) has a permeability that is at least 20% higher than the original permeability of the underground oil reservoir.

The same applies to the compounds (20 to 26), which are also referred to as waterways or flood routes. The permeability of the compounds (20 to 26) is also at least 20%, preferably at least 35 50%, more preferably at least 75% and most preferably at least 90% higher than the permeability of the storage zones (1 1 to 15).

The permeability of the high-permeability zone (1) in the vicinity of the injection well (IB) may exceed the permeability of the compounds (20 to 26). In general, the permeability of the high permeability zone (1) is at least 10% higher than the permeability of the compounds (20 to 26). The extent of the high-permeability zone (1) in the vicinity of the injection well (IB) depends on the properties of the underground oil reservoir and on the duration of the implementation of process step b). The horizontal extent of the highly permeable zone (1) is generally in the range of 1 to 100 m, preferably in the range of 3 to 60 m, particularly preferably in the range of 4 to 50 m. The horizontal extent of the highly permeable zone (1) is measured from the center of the injection well (IB). The extent of the high-permeability zone (1) is particularly great when the petroleum-bearing layer (production layer) of the underground oil reservoir as deposit matrix contains loose rocks, such as sand, from which the petroleum can be washed out.

The vertical extent of the high-permeability zone (1) also depends on the properties of the underground oil reservoir and on the duration of the execution of the process step (b). The vertical extent of the high permeability zone (1) generally corresponds to the thickness of the production layer and is generally in the range of 0.5 to 50 m, preferably in the range of 0.5 to 20 m and more preferably in the range of 0.5 to 10 m and in particular in the range of 0.5 to 5 m. The extent of the compounds (20 to 26) also depends on the nature of the underground oil reservoir and on the duration of the implementation of the process step b). The length of the connections (20 to 26) generally corresponds at least to the distance of the injection well (I B) from the production wells (PB). The distance of the injection well (I B) from the production wells (PB) is generally in the range of 50 m to 10 000 m. The length of the joints (20 to 26) is generally greater than the distance between the injection well (IB) and production wells (PB), since the joints (20 to 26) are only in exceptional cases on a straight line between the injection well (IB) and production well ( PB).

The spatial location and shape of the compounds (20 to 26) are strongly influenced by the geological conditions in the underground oil reservoir, with geological disturbances such as clefts and other geological irregularities having a particularly large impact. The spatial location and shape of the connections (20 to 26) is therefore normally difficult to diagnose or proportion.

During process step b), oil is extracted from the production wells (PB). In general, in process step b), oil is extracted from all production wells (PB) belonging to a cluster. Process step b) is generally carried out until production dilution exceeds the limit of economic efficiency. This limit varies for different deposits, depends on current oil prices and is usually in the 60 to 95% range. One speaks about the natural oil drainage, if the oil predominantly the deposit water (initial water) contains. If the production dilution by flood water (flooding (FM)) increases, this can be called water breakthrough or flooding breakthrough. Production dilution is understood according to the invention to mean the state in which at least 50% by weight, preferably at least 70% by weight and particularly preferably at least 80% by weight, of flooding agent (FM) is conveyed from the production wells (PB), the wt .-% - each refer to the total weight of the fluids taken from the production wells (PB).

The present invention thus also provides a process in which process step b) is carried out until at least 50% by weight of fluxing agent (FM) is taken from the production wells (PB), based on the total weight resulting from the production wells (PB ) taken out liquids.

Process step c) and process step d): In process step c), the injection of a flood medium (FM) through the at least one injection well (IB) is set.

Subsequently, in method step d), the highly permeable zone (1) is blocked in the vicinity of the at least one injection bore (IB).

In a preferred embodiment, a flowable composition (FZ) is injected through the injection bore (IB) into the highly permeable zone (1) for this purpose.

The subject matter of the present invention is thus also a method in which, in method step d), a flowable composition (FZ) is injected into the highly permeable zone (1) through the at least one injection bore (IB) in order to block it.

Flowable means according to the invention in connection with the flowable composition (FZ) that the flowable composition (FZ) by means of conventional pumps in the injection well (IB) and the highly permeable zone (1) can be pumped.

Flowable compositions (FZ) which are preferred according to the invention have a flowable viscosity or consistency after production. This flowable viscosity or consistency makes it possible to pump the flowable composition (FZ) into the injection well (IB) or into the highly permeable zone (1) in the vicinity of the injection well (IB) in the underground oil reservoir. After injecting according to method step d) of the method according to the invention and before injecting a flooding agent (FM) according to method step e), the consistency or viscosity of the flowable composition (FZ) in the highly permeable zone (1) changes in the vicinity of the injection well (IB ) in the underground oil reservoir. The viscosity or consistency of the flowable composition (FZ) changes in the way that the viscosity increases significantly. The viscosity generally increases to viscosities of at least 1,000 mPas, preferably at least 5,000 mPas and particularly preferably at least 10,000 mPas. The viscosity of the flowable composition (FZ) preferably increases to values which are greater than the viscosity of the petroleum remaining in the stagnation zones (11 to 15).

It is also possible that the consistency of the flowable composition (FZ) changes from a flowable consistency to a no longer flowable consistency. The consistency of the flowable composition (FZ) can also be converted into a solid consistency after injection into the high permeability zone (1).

According to the invention, the term "after preparation of the flowable composition (FZ)" means that the flowable composition (FZ) after completion of the preparation for a period of at least 10 minutes, preferably at least 30 minutes and more preferably at least 1 hour, their flowable consistency or The significant increase in the viscosity of the flowable composition (FZ) or the change in the consistency of a flowable consistency into a no longer flowable or solid consistency in the high-permeability zone (1) in the underground oil reservoir generally takes place in Periods in the range of greater than 1 hour to 3 days, preferably in the range of greater than 1 hour to 48 hours, more preferably in the range of 3 hours to 36 hours, wherein the periods from the end of Injizierens according to method step d) measured.

In other words, during or after process step d), the flowable composition (FZ) transforms into a non-flowable composition (LCF). As a result, the blocking of the high-permeability zone (1) is achieved and the blocked zone (10) is formed. According to the invention, "non-flowable" means that the non-wettable composition (LCF) is not displaced by the flooding agent in the vicinity of the disused injection well (IBt) .The non-flowable composition (LCF) generally has a viscosity of at least 1,000 mPas , preferably at least 5,000 mPas and more preferably at least 10,000 mPas, Preferably, the viscosity of the non-flowable Composition (nFZ) greater than the viscosity of the oil remaining in the storage zones (1 1 to 15).

The present invention thus also provides a process in which the flowable composition (FZ) in the highly permeable zone (1) after process step d) and before process step e) is converted into a non-flowable composition (nFZ), whereby a blocked zone ( 10) in the vicinity of the injection well (IB) is formed. The present invention thus also provides a process in which the non-flowable composition (NSF) has a viscosity of at least 1000 mPas.

Suitable flowable compositions (FZ) which meet the above requirements are known in principle to those skilled in the art. Suitable flowable compositions (FZ) are for example selected from the group consisting of:

(i) curable mineral flowable compositions (FZ),

 (ii) flowable compositions (FZ) containing shear thinning mineral thickening agents,

 (iii) flowable compositions (FZ) containing shear thinning organic polymers,

 (iv) flowable thermogels,

 (v) flowable compositions (FZ) containing water-swellable polymers and

 (vi) Two-component flowable systems forming polymeric compounds. As hardenable mineral flowable compositions (FZ; i), for example, flowable cement compositions or flowable gypsum compositions can be used. These flowable compositions (FZ) have a flowable consistency upon production at the surface of the subterranean crude oil deposit. After injecting these compositions according to process step d), these compositions cure in the high-permeability zone (1) and then have a solid consistency.

As flowable compositions (FZ) containing shear thinning mineral thickeners (ii), for example, aqueous compositions are suitable, which are thickened with a shear-thinning clay mineral. Layered silicates such as Laponite, bentonite and hectorite are suitable as shear-thinning clay minerals, for example. The shear thinning clay minerals are included in concentrations ranging from 0.1 to 5 wt .-%, based on the total weight of the flowable composition (FZ) used.

According to the invention, "shear-thinning" is understood to mean that the viscosity of the flowable composition (FZ) decreases under the action of shear forces and increases again at rest, ie in the absence of shear forces After completion of the injection of the flowable composition (FZ) according to method step d), the viscosity of this flowable composition (FZ; ii) in the high-permeability zone (1) thus increases in the vicinity of the injection well This is attributable to the fact that, upon completion of the injection according to method step d), no more shear forces act on the flowable composition (FZ; ii).

As flowable compositions (FZ) containing a shear thinning organic polymer (iii), for example, aqueous compositions thickened with a shear thinning organic polymer are suitable. The content of the shear-thinning organic polymer in the flowable composition (FZ) is generally in the range of 0.1 to 5 wt .-%, based on the total weight of the flowable composition (FZ; iii). Suitable shear-thinning organic polymers are, for example, biopolymers such as xanthan, diutan and glucans. Preferred shear thinning organic polymer is a glucan having a β-1,3-glycosidically linked main chain and β-1,6-glycosidically linked side groups having a weight-average molecular weight M _w in the range of 1.5 × 10 ⁶ to 25 × 10 ⁶ g / mol. The flowable compositions (FZ; iii) containing a shear thinning organic polymer have a low viscosity as described above under the action of shear forces. At rest, that is in the absence of shear, the viscosity of these compositions also increases significantly.

As the flowable thermogels (iv), for example, aqueous compositions containing 0.1 to 5% by weight of a polymer which causes low viscosity in the aqueous composition at low temperatures and higher in viscosity at higher temperatures are suitable. In the event that a thermogel (iv) is used as the flowable composition (FZ), the flowable composition (FZ; iv) thus has a low viscosity at the temperatures at the surface of the underground oil reservoir. The temperatures at the surface of the underground oil reservoir are generally in the range of 0 to 40 ° C. At the temperatures in the high-permeability zone (1) in the underground oil reservoir, the viscosity of the flowable composition (FZ; iv) increases. Thermogels (iv) are preferred in underground oil reservoirs used in the high-permeability zone (1) has a reservoir temperature (T _L ) of at least 60 ° C, preferably at least 70 ° C. The thermogels are particularly suitable for underground oil reservoirs, which have a reservoir temperature (T _L ) in the range of 70 to 150 ° C in the high permeability zone (1).

As polymers which can be used for the preparation of the thermogels, cellulose ethers are particularly preferred. As cellulose ethers, it is possible to use all known cellulose ethers obtainable by partial or complete substitution of the hydrogen atoms of the hydroxyl groups of cellulose. Suitable groups for the substitution of the hydrogen atoms are, for example, alkyl and / or aryl groups. The etherification of the cellulose is generally carried out by reaction with the respective halides (for example with methyl, ethyl, propyl or benzyl chloride), with epoxides (such as ethylene, propylene or butylene oxide) or with activated olefins (such as Acrylonitrile, acrylamide or vinylsulfonic acid). Preferred cellulose ethers are, for example, methylcellulose, methylhydroxyethylcellulose or methylhydroxypropylcellulose and also mixtures of these cellulose ethers. Particularly preferred are methyl cellulose or methyl hydroxypropyl cellulose and mixtures of these two cellulose ethers. As flowable compositions (FZ) containing a water-swellable polymer (v), for example, aqueous compositions containing 0.1 to 5 wt .-% of a water-swellable polymer, based on the total weight of the flowable composition (FZ) are suitable. As water-swellable polymers, for example, highly crosslinked polymers of acrylic or methacrylic acid are suitable, which are also referred to as superabsorbent. For this purpose, the water-swellable polymers are first dispersed in water at the surface of the underground oil reservoir and then injected according to process step d) in the highly permeable zone (1) of the vicinity of the injection well (IB) in the underground Erdöllagerstätte. It is important that during dispersing the swellable polymer is not completely wetted with water. After completion of process step d), the water-swellable polymer swells in the high-permeability zone (1), whereby a significant increase in the viscosity of the flowable composition (FZ) is achieved. The term "water-swellable" is understood according to the invention to mean that the water-swellable polymer changes its shape and increases its volume when it is exposed to water In general, water swelling achieves an increase in volume of at least 150%, in particular at least 200%, based on the volume of the water-swellable water Poly (poly (ethylene glycol) di (meth) acrylate having a weight-average molecular weight (M _w ) of at least 2 500 g / mol, preferably in the range from 2500 to 10 000 g / mol, more preferably in the Section 5,000 to 10,000 g / mol and more preferably in the range of 8,000 to 10,000 g / mol.

Suitable two-component systems (vi) are flowable compositions (FZ) which contain a first component (K1) and a second component (K2) which can react with one another, forming a polymeric compound. Examples of suitable two-component systems (vi) are those which contain a component (K1) and a component (K2) which, after injection according to method step d), polymerize in the high-permeability zone (1).

A preferred two component system (vi) is a system which polymerizes to polysilicic acid in the high permeability zone (1). This two-component system (vi) contains as component (K1) a water-soluble alkali metal silicate. As component (K2) this system receives an acid. In the high-permeability zone (1), the acid catalyses the polymerization of the water-soluble alkali silicates to insoluble polysilicic acid.

As the water-soluble alkali metal silicates, sodium silicates, potassium silicates and lithium silicates are preferred, with sodium and potassium silicates being particularly preferred. These silicates are also referred to as water glass. The preferred acid component (K2) may be an organic, an inorganic or a Lewis acid.

As component (K2), preference is given to using inorganic acids or Lewis acids. As Lewis acids, for example, divalent or trivalent metal salts may be used, with aluminum (III) salts, such as aluminum trichloride, and calcium (III) salts, such as calcium (II) chloride, being preferred.

Hydrochloric acid and sulfuric acid are preferred as inorganic acids, with hydrochloric acid being particularly preferred.

The acid used as component (K2) catalyzes the polymerization of the alkali silicates, forming water-insoluble polysilicic acid. Depending on the alkali silicate used and depending on the acid used, the polysilicic acid may contain further metal ions, such as, for example, sodium, potassium, lithium, calcium and aluminum ions. Suitable water glasses, as well as the polymerization of these water glasses with acids are known in the art. The polymerization of alkali metal silicates with the Lewis acid calcium chloride is also known as the joosten process. The joosten process accordingly forms polysilicic acids containing calcium ions. Such compounds are also referred to as calcium silicate gels. In the case where two-component systems (vi) are used which polymerize to form polysilicic acids, the mixture of components (K1) and (K2) can take place at the surface of the underground oil reservoir. In addition, it is also possible to carry out the mixing of the two-component system (vi) directly in the injection well (IB). In this case, the two components (K1) and (K2), preferably in an aqueous mixture, are injected by separate feeds into the injection well. The mixing of the components (K1) and (K2) takes place directly in the injection well (IB). In addition, it is possible to inject the components (K1) and (K2) directly into the high-permeability zone (1) by means of two separate injection strands, so that the mixing of the two components (K1) and (K2) directly in the high-permeability zone (FIG. 1).

It is also possible to sequentially inject the components (K1) and (K2) through the injection well (I B) into the high permeability zone (1). For this purpose, generally two aqueous formulations (F1) and (F2) are injected successively through the injection well (IB) into the highly permeable zone (1), the formulation (F1) the component (K1) and the formulation (F2) the component ( K2). The mixing of the two formulations (F1) and (F2) to form the flowable composition (FZ) takes place in this embodiment only in the high-permeability zone (1).

The present invention thus also provides a process in which the flowable composition (FZ) is a two-component system (vi) which contains a water-soluble alkali silicate as component (K1) and an acid as component (K2).

Another preferred two-component system (vi) is a flowable composition which polymerizes in the high-permeability zone (1) to form water-insoluble metal hydroxide or metal oxyhydrate gels. For this purpose, a metal compound is used as component (K1), preferably a water-soluble metal compound selected from the group consisting of iron (l l) - and iron (ll l) salts, vanadium salts, zirconium salts and aluminum (ll l) salts. Preferred as component (K1) are aluminum (III) salts, such as, for example, aluminum chloride, aluminum nitrate, aluminum sulfate, aluminum acetate or aluminum acetylacetonate. Already partially hydrolyzed aluminum salts can also be used as aluminum (III) salts, the above preferences applying correspondingly. An example of a partially hydrolyzed aluminum salt is aluminum hydroxychloride. Particularly preferred aluminum (II) salt is aluminum chloride and the partially hydrolyzed aluminum hydroxychloride.

As component (K2), a water-soluble activator is used in this flowable composition (FZ; vi), which preference is given to the polymerization of the metal salts the aluminum (II l) salts, catalyzed. As water-soluble activators preferably activators are selected from the group consisting of urea, substituted ureas such as Ν, Ν'-alkyl ureas, in particular Ν, Ν'-dimethylurea and hexamethylenetetramine (urotropin). The water-soluble activators (component (K2)) release bases (or bind acids) under the conditions of the underground oil reservoir and thus lead to an increase in the pH value. By increasing the pH value, highly viscous, water-insoluble gels are formed, which comprise metal ions, hydroxide ions and optionally further components.

In the case of the use of aluminum compounds, aluminum hydroxide or aluminum oxyhydrate gels form, which may of course comprise further components, such as, for example, anions of the aluminum salt used. As a result of the formation of the polymeric, water-insoluble metal hydroxide gels or metal oxyhydrate gels, the viscosity of the two-component system (vi) in the high-permeability zone (1) increases as a flowable composition (FZ; vi), thereby achieving blocking of the high-permeability zone (1) ,

Also when using the above-described two-component system (vi), which reacts to water-insoluble polymeric metal hydroxides or metal oxyhydrate, the components (K1) or (K2) can be mixed on the surface of the underground Erdöllagerstätte. In addition, it is possible to introduce the two components (K1) and (K2) separately into the injection bore (IB), so that a mixing of the components (K1) and (K2) takes place only in the injection bore (I B). In addition, it is also possible to inject the two components (K1) and (K2) by separate injection strands directly into the highly permeable zone (1), so that mixing takes place only in the highly permeable zone (1).

It is also possible to sequentially inject the components (K1) and (K2) through the injection well (I B) into the high permeability zone (1). For this purpose, generally two aqueous formulations (F1) and (F2) are injected successively through the injection well (IB) into the highly permeable zone (1), the formulation (F1) the component (K1) and the formulation (F2) the component ( K2). The mixing of the two formulations (F1) and (F2) to form the flowable composition (FZ) takes place in this embodiment only in the high-permeability zone (1).

Preference is given here to a two-component system (vi) which contains as component (K1) an aluminum chloride (AICI ₃ ) and as component (K2) urea. These two-component systems (vi) are described, for example, in European patent applications EP 2 333 026 and EP 2 568 029, to which reference is hereby made. In the event that two aqueous formulations (F1) and (F2) are used for the two-component system described above, these formulations contain 4 to 10 wt .-% of the metal salt, preferably aluminum (II) chloride and 16 to 36 wt .-% of the activator, preferably urea, in each case based on the total weight of the aqueous formulations (F1) and (F2). The amounts of metal salt and activator in this case relate to the anhydrous compounds.

The present invention thus also provides a process in which the flowable composition (FZ) is a two-component system (vi) which contains as component (K1) a water-soluble metal compound selected from the group consisting of iron (II) and iron ( l ll) salts, vanadium salts, zirconium salts and aluminum (II l) salts and contains as component (K2) a water-soluble activator selected from the group consisting of urea, substituted Ν, Ν'-alkyl ureas and hexamethylenetetramine.

Among the flowable compositions (FZ), the above-described two-component systems (vi) are preferred. In addition, the flowable compositions (FZ) may contain further additives as described above for the fluxing agent (FM). The explanations and preferences for flooding agent (FM) therefore apply accordingly to the flowable composition (FZ). As a further option, in the final phase of flooding, it is possible to inject flooding agent (FM) into the deposit with increasing viscosity, whereby the maximum viscosity of the flooding agent (FM) is reached at the end of the flooding measures.

After completion of process step d), the highly permeable zone (1) in the vicinity of the injection well (I B) is blocked. The state after carrying out the method step d) according to the invention is shown by way of example in FIG. The blocked zone (10) in the vicinity of the injection well (I B) thus interrupts the hydrodynamic communication between the injection well (I B) and the production wells (PB1 to PB7). In addition, the blocked zone (10) interrupts the hydrodynamic communication of the production wells (PB1 to PB7) with each other.

The subject matter of the present invention is therefore also a method in which after step d) the blocked zone (10) interrupts the hydrodynamic communication between the production wells (PB1 to PB7) and the injection well (IB) and between the production wells (PB1 to PB7) , After blocking the highly permeable zone (1) to form the blocked zone (10), the injection well (IB) is injected through the in step d) flooding agent (FM) was injected, usually shut down (terminated). In the event that flood medium (FM) was injected through two or more injection wells (IB) in process step b), all injection wells (IB) are generally shut down (terminated). The disused injection bore (IBt) carries the reference symbol IBt in FIG.

The shutdown of the injection well (IB) can be carried out by conventional methods known in the art. For example, the injection well (IB) can be filled with cement. Here, the cement-blocked area (4) forms. In the event that the injection well has a perforation region (5), this is also generally closed by cement (4). The shut-down injection well (IBt) is shown by way of example in FIG. Figure 5 shows a vertical section through the underground oil reservoir.

The subject of the present invention is therefore also a method in which the injection well (IB) is closed after process step d) and before process step e), whereby a shut-down injection well (IBt) is obtained.

Process step e).

After decommissioning of the injection well (IB) to form the disused injection well (IBt), the injection of a flood medium (FM) is continued through at least one new injection well (nIB) in process step e). As a new injection well (NIB), another well can be drilled into the underground oil reservoir. By "further drilling" is meant here that, in addition to the injection bores (IB) and production bores (PB) brought down in process step (a), a further, that is to say additional, borehole is drilled into the underground oil reservoir.

In a preferred embodiment, however, the flooding agent (FM) in process step e) is injected through a bore which has already been drilled in process step a) into the underground oil reservoir. As a new injection well (nIB), in a preferred embodiment, a production well (PB) is used, from which crude oil was extracted in process step b).

The subject matter of the present invention is therefore also a method in which at least one borehole is used as the new injection well (nIB), which was drilled into the underground crude oil deposit in process step a). Injecting a flooding agent (FM) according to method step e) can take place by exactly one new injection well (nIB) or by two or more new injection wells (nIB). In the event that a production well (PB) is used as the new injection well (nIB) from which oil was produced in process step b), the number of production wells (PB) is reduced by one production well (PB). In method step e), the number of production bores (PB) from which crude oil has been taken off in method step b) has thus been reduced by one production bore (PB) in method step e). The subject matter of the present invention is thus also a method in which at least one production well (PB) is used as at least one new injection well (NIB), from which crude oil was extracted in process step b).

The injection of a flooding agent (FM) according to method step e) is shown by way of example in FIG. The new injection well (nIB) uses the former production well (PB5).

It is also possible to use a part of the disused injection well (IBt) as the new injection well (NIB). For this purpose, above the cement-blocked area (4) of the disused injection well (IBt), a deflected well is drilled into the subterranean crude oil deposit. In this embodiment, the new injection well (nIBt) is composed of a part of the disused injection well (IBt) and a newly deposited deflected part. This embodiment is shown by way of example in FIG. The new injection well (nIB) is hereby drilled from the disused injection well (IBt) into the subsurface oil reservoir (6) placing the new injection well (nIB) outside the blocked zone (10).

In step e), a flood medium (FM) is injected through the new injection well (NIB) into the subterranean crude oil deposit and oil is withdrawn from the remaining production wells (PB). In this case, the same flooding agent as in method step b) can be injected as flooding agent (FM). It is also possible to use in process step e) a flooding agent (FM) different from process step b). For the flooding agent (FM) which is injected in process step e), the statements and preferences for the flooding agent (FM) which was injected in process step b) apply accordingly.

FIG. 7 shows, by way of example, the implementation of method step e) according to the invention. In FIG. 7, the new production well (NIB) used is the former production well (PB3) from which crude oil was extracted in process step b). Through the new injection well (nIB), the flood medium (FM) passes along the Connection (22) in the direction of the blocked zone (10) in the vicinity of the disused injection well (I Bt).

Since the near area (10) of the shut-down injection well (I Bt) is blocked, the flood medium (FM) spreads along the flood red (3) in the underground oil reservoir. The flooding agent (FM) thus displaces the oil contained in the storage zones (1 1 to 15) in the direction of the remaining production wells (PB1, PB2 and PB4 to PB7). In the exemplary illustration according to FIG. 7, in particular, the petroleum in the accumulation zones 14 and 15 is displaced in the direction of the production bores PB2 and PB4. As a result, the production rate of crude oil from the production wells PB2 and PB4 is significantly increased.

The process according to the invention can be repeated as often as desired or in partial steps. In the event that a flood or water breakthrough is registered in the remaining production wells (PB1, PB2 and PB4 to PB7) and a further highly permeable zone (1) has formed near the new injection well (nIB), the process steps c ) to e). For this purpose, the further highly permeable zone (1) in the vicinity of the new injection well (nI B) as described above, blocked according to process step d) and the injection of a flood medium (FM) by another new injection well (nI B) according to process step e) continues. As described above, one of the remaining production wells (PB) can be used for this purpose. LIST OF REFERENCE NUMBERS

IB injection hole

 IBt disused injection well

nI B new injection well

PB1 - PB7 production wells

1 highly permeable zone in the vicinity of the injection well I B

 2 flood front (method according to the prior art)

 3 flood front (method according to the invention)

4 cement-blocked area

 5 perforation area

 6 underground oil reservoir

10 blocked zone in the vicinity of the shut-down injection well IBt 1 1 - 15 zones containing oil (congestion zones) 20 - 26 connections between the injection hole IB and the

 Production wells PB1 - PB7 with high permeability (waterways and flood routes) The figures show in detail:

FIG. 1

 FIG. 1 shows the top view (horizontal section) of an underground oil reservoir towards the end of the secondary or tertiary production methods.

FIG. 2

 Figure 2 shows the top view (horizontal section), a method of the prior art (RU 2 217 582), in which after completion of the secondary or tertiary production methods, further crude oil is promoted. For this purpose, the injection of the flooding agent (FM) is displaced from the original injection well (I B) into the production well (PB5).

FIG. 3

 Figure 3 shows the top view (horizontal section), a method of the prior art (RU 2 217 582), in which after completion of the secondary or tertiary production methods, further petroleum is promoted. For this purpose, a new additional injection well (nI B) is drilled into the underground oil reservoir.

FIG. 4

FIG. 4 shows the plan view (horizontal section) through an underground oil reservoir in which the method according to the invention for the extraction of crude oil is carried out.

FIG. 5, FIG. 6

Figures 5 and 6 show a vertical section through an underground oil reservoir in which the process according to the invention for the extraction of petroleum is performed.

FIG. 7

FIG. 7 shows the plan view (horizontal section) through an underground oil reservoir in which the method according to the invention for the extraction of crude oil is carried out.

The present invention is further illustrated by, but not limited to, the following examples. Examples:

Exemplary Embodiment 1 An underground oil reservoir with the following parameters is developed:

Depth (depth): 800 to 900 meters (m) above normal zero (NN)

 Net capacity of the oil-bearing layer: 25 to 35 m

 Porosity: 30%

Permeability: 400 to 14,000 mD

 Initial water saturation: 8%

Initial deposit temperature (T _L ): 37 ° C

 Initial reservoir pressure: 85 bar

Initial oil density: 0.900 g / cm ³

Viscosity of petroleum: 180 mPas at 37 ° C

Initial ratio of natural gas / petroleum: 14 m ³ / m ³

In step a), seven vertical holes are drilled into the petroleum bearing layer of the underground oil reservoir. In method step b), a bore is used as the injection bore (I B). The remaining six holes will be used as production wells (PB).

Subsequently, process step b) is carried out for a period of five years, wherein water is injected as flooding agent (FM) through the injection well (I B). After five years, water flooding stops as production dilution is registered.

Due to the relatively high viscosity of the petroleum remaining in the underground oil reservoir, process step b) is continued with water vapor as flooding agent (FM). For this purpose, the injection well (I B) water vapor at a temperature in the range of 250 to 300 ° C and a pressure in the range of 90 to 100 bar and injection rates of about 150 tons / day injected into the underground oil reservoir. The injection of water vapor is carried out for a period of five years.

As a result, a highly permeable zone (1) is formed in the vicinity of the injection bore (IB). The injection well (IB) is in good hydrodynamic contact via the highly permeable zone (1) with at least 5 of the production wells (PB) brought down in process step a). The production dilution is in the range of 94 to 95%. The degree of de-oiling is 54%, ie 54% of the oil originally contained in the underground oil reservoir was extracted. According to process step c), the injection of the water vapor used as flooding agent (FM) through the injection well (IB) is set. The direct temperature measurement shows that the highly permeable zone (1) has a temperature in the range of 220 to 230 ° C.

In order to interrupt the hydrodynamic communication between the injection well (IB) and the production wells (PB), in step d) the highly permeable zone (1) in the vicinity of the injection well (I B) is blocked.

For blocking in process step d), a flowable composition (FZ) is injected through the injection well (IB) into the highly permeable zone (1). For this purpose, a two-component system (vi) is used. Two aqueous formulations (F1) and (F2) are successively injected into the highly permeable zone (1) of the underground oil reservoir, so that the flowable composition (FZ; vi) is formed in the high-permeability zone (1). Formulation (F1) contains 84% by weight of water and as component (K1) 16% by weight of aluminum (II) chloride (AICI ₃ ), based on the total weight of formulation (F1) and based on anhydrous aluminum (II l) chloride.

The formulation (F2) contains 50% by weight of urea and 50% by weight of water, based on the total weight of the formulation (F2).

The formulations (F1) and (F2) are injected in equal volume proportions. The flowable composition (FZ) which forms in the highly permeable zone (1) thus contains 8% by weight of AICI ₃ , 25% by weight of urea and 67% by weight of water.

After injection (method step d)), the formulations (F1) and (F2) mix in the high-permeability zone (1) and form a highly viscous gel under the influence of the temperature of the highly permeable zone (1).

In Table 1 below, the time until the formation of the highly viscous gel is exemplified for different temperatures.

Table 1 :

 Temperature [° C] 100 90 80 70 60

Gelation time [Days] 1/4 1 3 6 30 In Table 2 below, the time to gelation for various mixtures of AICI ₃ (calculated as anhydrous product), urea and water at 100 ° C and 1 10 ° C is shown. It can be seen that as the amount of activator urea decreases, the time to form the gel becomes longer and longer.

Table 2

The described formulations based on dissolved metal compounds, in particular aluminum salts and activators have the advantage that inorganic gels are formed. The gels are stable up to temperatures of 300 ° C and are therefore particularly suitable for deposits with very high temperatures (hot deposits after steam flooding).

In order to block the highly permeable zone (1), in method step d) about 2000 m ³ (sum of the formulations (F1) and (F2) are injected through the injection well (IB) into the highly permeable zone (1) of the underground oil reservoir.

The viscosity of the high-viscosity gel is over 1000 mPas. After blocking the high-permeability zone (1), the injection well (IB) is sealed with cement, whereby the shut-down injection well (IBt) is formed.

Subsequently, through a former production well (PB) serving as a new injection well (nIB), in process step e), water is injected as flooding agent (FM) and oil is extracted from the remaining production wells (PB). As a result, a significant increase in the degree of deoiling of the underground oil reservoir is achieved.

Embodiment 2.

There is developed a Erdöllagerstätte initially having the same parameters as in Example 1. In step a), eight vertical holes are drilled in the underground oil reservoir. One hole is used as the injection hole (I B), the remaining holes are used as production holes (PB).

In process step b) water (reservoir water) is injected as flooding agent (FM) through the injection well (IB) for a period of seven years. The water is injected at a pressure in the range of 10 to 20 bar and rates in the range of 400 to 500 m ³ / day in the underground oil reservoir.

After seven years, the production dilution increases to 85 to 90 wt .-%. In the vicinity of the injection well (I B) has a highly permeable zone (1) is formed, which has a good hydrodynamic communication to at least five production wells (PB). The remaining oil in the underground oil reservoir has a relatively high viscosity. The highly permeable zone (1) in the vicinity of the injection well (IB) is cooled by the long-term water flooding and has a temperature in the range of 12 to 15 ° C.

In order to block the highly permeable zone (1), in method step d) a flowable composition (FZ) is injected through the injection bore (IB) into the highly permeable zone (1).

It is a flowable composition (FZ) used with the following ingredients:

 Water-soluble sodium silicate: 10% by weight,

Hydrochloric acid or sulfuric acid: 1, 2% wt .-%, (based on HCl or H ₂ S0 ₄ )

Monoethanolamine: 0.5 wt .-% and

Water: 88.3% by weight.

About 1000 m ^{3 of} this flowable composition (FZ) are pressed into the deposit. Subsequently, 7 to 5 m ³ cement broth are injected to shut down the injection well (IB). The flowable composition (FZ) forms a highly viscous gel within 1 to 2 days, blocking the high permeability zone (1). Subsequently, according to method step e), steam is injected as flood medium (FM) through a former production well serving as a new injection well (IB) and crude oil is extracted from the remaining production wells. As a result, a significant increase in the degree of deoiling of the underground oil reservoir is achieved.

Claims

claims A method of extracting oil from a subsurface oil reservoir, comprising the steps of: a) drilling at least one injection well (IB) and at least two production wells (PB) into the underground oil reservoir. b) injecting a flooding agent (FM) through the at least one Injection well (IB) into the underground oil reservoir and extraction of petroleum from the at least two production wells (PB), forming a highly permeable zone (1) in the vicinity of the at least one injection well (IB) in the subterranean crude oil deposit, c) adjusting the injection of the Flooding agent (FM) through the at least one injection well (IB), Blocking the high permeability zone (1) in the vicinity of the at least one injection well (IB), e) injecting a flood medium (FM) through at least one new injection well (NIB) into the underground well deposit and extracting oil from at least one production well (PB). A method according to claim 1, characterized in that underground Erdöllagerstätte after step b) compounds (20 to 26) through which the production wells (PB) with each other and to the injection well (IB) via the highly permeable zone (1) are in hydrodynamic communication. 3. The method according to claim 1 or 2, characterized in that in step a) at least one production well (PB) is drilled more in the underground Erdöllagerstätte, as injection wells (IB) are brought down. 4. The method according to any one of claims 1 to 3, characterized in that step b) is carried out until at least 50 wt .-% flooding (FM) taken from the production wells (PB) is based on the total weight of the fluids extracted from the production wells (PB). A method according to any one of claims 1 to 4, characterized in that the high permeability zone (1) has a permeability at least 20% higher than the initial permeability of the underground oil reservoir. Method according to one of claims 1 to 5, characterized in that in step d) by the at least one injection hole (IB) a flowable composition (FZ) is injected into the highly permeable zone (1) to block them. Method according to one of claims 1 to 6, characterized in that the flowable composition (FZ) in the high-permeability zone (1) after process step d) and before process step e) into a non-flowable composition (nFZ) converts, whereby a blocked zone (10) arises in the vicinity of the injection well (IB). Method according to one of claims 1 to 7, characterized in that after process step d) the blocked zone (10) the hydrodynamic communication between the production wells (PB1 to PB7) and the injection well (IB) and between the production wells (PB1 to PB7) with each other interrupts. A method according to claim 7 or 8, characterized in that the non-flowable composition (nfz) has a viscosity of at least 1000 mPas. Method according to one of claims 1 to 9, characterized in that the injection well (IB) after step d) and before step e) is closed, whereby a disused injection well (IBt) is obtained. Method according to one of claims 1 to 10, characterized in that the flowable composition (FZ) is selected from the group consisting of (i) curable mineral flowable compositions (FZ), (ii) flowable compositions (FZ) containing shear thinning mineral thickening agents, (iii) flowable compositions (FZ) containing shear thinning organic polymers,  (iv) flowable thermogels,  (v) flowable compositions (FZ) containing water-swellable polymers and  (vi) Two-component flowable systems forming polymeric compounds. Method according to one of claims 1 to 1 1, characterized in that the flowable composition (FZ) is a two-component system (vi) which contains as component (K1) a water-soluble alkali silicate and as component (K2) an acid. 13. The method according to any one of claims 1 to 1 1, characterized in that the flowable composition (FZ) is a two-component system (vi) having as component (K1) a water-soluble metal compound selected from the group consisting of iron (II) - And iron (III) salts, vanadium salts, zirconium salts and aluminum (III) salts and contains as component (K2) a water-soluble activator selected from the group consisting of urea, substituted Ν, Ν'-alkyl ureas and Contains hexamethylenetetramine. 14. The method according to any one of claims 1 to 13, characterized in that as a new injection well (nIB) at least one hole is used, which was drilled in step a) in the underground Erdöllagerstätte. 15. The method according to any one of claims 1 to 14, characterized in that as at least one new injection well (nIB) at least one production well (PB) is used, was funded from the process step b) oil.