WO2013050364A1

WO2013050364A1 - Method for extracting petroleum from an underground deposit

Info

Publication number: WO2013050364A1
Application number: PCT/EP2012/069450
Authority: WO
Inventors: Vladimir Stehle; Bernd Leonhardt; Benjamin Wenzke
Original assignee: Wintershall Holding GmbH
Priority date: 2011-10-04
Filing date: 2012-10-02
Publication date: 2013-04-11
Also published as: CA2843389A1; EP2764069A1; EA201490694A1; CN103930514A; IN2014CN03003A; MX2014001867A

Abstract

PF72060 26 Method for extracting petroleum from an underground deposit Abstract 5 Method for extracting petroleum, wherein an aqueous flood medium comprising water, a glucane, urea and optionally surfactants is injected into the petroleum formation and petroleum is extracted from the formation through at least one production borehole, wherein the formation has a temperature of at least 60°C. The formulation forms foams in situ, under the influence of the temperature, in the formation. 10

Description

Process for extracting oil from an underground deposit

The present invention relates to a method for crude oil extraction, in which an aqueous flooding medium comprising water, a glucan, urea and optional surfactants is injected into the petroleum formation and the formation takes petroleum through at least one production well, wherein the formation has a temperature of at least 60 ° C. , The formulation forms in-situ foams in the formation under the influence of formation temperature as well as gases which lead to the formation of an alkaline bank in the oil-bearing layer. In natural oil deposits, petroleum is present in cavities of porous reservoirs which are closed to the earth's surface by impermeable facings. In addition to crude oil, including the naturally dissolved natural gas in a deposit continues to contain more or less saline water. The cavities may be very fine cavities, capillaries, pores, for example those having a diameter of only about 1 μm; however, the formation may also have areas of larger diameter pores and / or natural fractures or cracks.

After the hole has been drilled into the oil-bearing layers, the oil initially flows to the production wells due to the natural deposit pressure and reaches the earth surface eruptively. This phase of crude oil production is called by the specialist primary production. With poor reservoir conditions, such as high oil viscosity, rapidly falling reservoir pressure, or large flow resistances in the oil-bearing strata, the eruption promotion quickly comes to a standstill. On average, only 2 to 10% of the oil originally present in the deposit can be extracted from primary production. For higher-viscosity petroleum eruptive production is usually not possible.

In order to increase the yield, therefore, the so-called secondary production methods are used. The most common method of secondary oil production is water flooding. In the process, water is injected into the oil-carrying layers through so-called injection bores. This artificially increases the reservoir pressure and forces the oil from the injection wells to the production wells. By flooding with promotion of higher-viscosity petroleum, the degree of exploitation can be increased only slightly.

In the case of water flooding, ideally, a water front emanating from the injection well should press the oil evenly over the entire petroleum formation to the production well. In practice, however, a petroleum formation has regions with different high flow resistance. In addition to finely porous, oil-saturated reservoir rocks with a high flow resistance for water, there are also areas with low resistance to flow for water, such as natural or artificial fractures and cracks or very permeable areas in the reservoir rock. Such permeable areas can also be areas which have already been substantially deoiled by the water. When water flooding the injected flood water flows naturally mainly by flow paths with low flow resistance of the injection well for production drilling. As a result, the fine-pored, high-flow, oil-saturated reservoir regions are no longer flooded, and increasingly more water and less oil are being pumped through the production wells. In this context, the expert speaks of a "dilution of production." The effects mentioned above are particularly pronounced in the case of higher-viscosity petroleum oils.The higher the petroleum viscosity, the more likely the rapid dilution of production.

In order to counteract the above-described negative effects in the extraction of petroleum, in particular viscous petroleum, various measures are known in the prior art.

For example, one can block the preferred flow paths for injected flood water. For this gel-forming formulations can be used which are comparatively low in viscosity before injection and form highly viscous gels after injection into the formation. As a result, preferred flow paths are blocked for the flood water and the water is diverted into not yet de-oiled areas. Such measures are also known as "conformance control" or "water shut-off". Altunina, LK, Kuvshinov, VA "Improved Oil Recovery of High-Viscosity Oil Pools with Physicochemical Methods and Thermal-Steam Treatments", Oil & Gas Science and Technology, Vol. 63 (2008), No. 1, pp. 37-48 Aqueous solutions of cellulose ethers are relatively low viscosity at room temperature and do not form highly viscous gels at elevated temperatures To reduce the oil viscosity and / or increase the viscosity of the aqueous flooding medium, measures to reduce the oil viscosity include, for example, C02 flooding and steam flooding the oil viscosity is reduced by the effect of the CO2 and in the Damp flood with the increase in temperature. The viscosity of the aqueous flooding media can be increased by the addition of suitable viscosity-increasing additives. These include, for example, the polymer flooding, in which one increases the viscosity of the aqueous phase by the addition of polymers or foam flooding.

For polymer flooding, a large number of different, thickening water-soluble polymers have been proposed, both synthetic polymers, such as

Polyacrylamide or copolymers of acrylamide and other monomers, in particular sulfonic acid groups having monomers and polymers of natural origin such as glucosylglucans, xanthans or diutans. Glucosylglucans are branched homopolysaccharides of glucose units. The preparation of such glucosyl glucans and their use for crude oil production is disclosed, for example, in EP 271 907 A2, EP 504 673 A1, DE 40 12 238 A1 and WO 03/016545. Glucosylglucans have a high temperature stability and are therefore particularly suitable for oil reservoirs high reservoir temperatures. Our prior application EP 1 1 154670.1 discloses a method of extracting oil from deposits having a deposit temperature of at least 70 ° C using glucans. Altunina, LK, Kuvshinov, VA and Stasyeva, LA "Thermoreversible Polymer Gels for EOR", in Recent Innovations in Oil and Gas Recovery, Istvän Lakatos (Ed.) - Akademiai Kiadö, Budapest, Progress in Oilfield Chemistry, Vol. 8, p 133 to 144, 2009 disclose the use of methylcellulose gels for tertiary petroleum production The gels may contain additives to increase the gelation temperature, such as ethanol, ammonium thiocyanate, thiourea or urea.

Various foam flooding techniques are disclosed in, for example, the following publications: US 5,074,358 and US 5,363,915 disclose tertiary petroleum production processes using foams. For example, CO2, N2 or CH4 can be used as foaming gases. Foaming may be accomplished by either alternately injecting gas and foam forming formulations into the formation or by forming a foam and injecting the foam into the formation (see, e.g., US 5,363,915, column 6, line 3 et seq.).

Drozdov A.N., Telkov V.P., Egorov Yu. A. at al. disclose in "Solution of Problems of Water-Gas Influence (WGI) on the Layer using jet and electric centrifugal pumping technology" - Society of Petroleum Engineers SPE Paper 1 17380 injecting a mixture of water, natural gas and surfactant into an oil reservoir to increase the Yield.

Hombrook MW, Dehgham K., Qadur S. Ostermann KD, Ogbe DQ "Effects of C0 ₂ addition to steam on west of crude oil / V" SPE, Reserrvoir Eng. - 1991 - 6 N ° 3, p.278-286 disclose a method in which a mixture of steam and CO2 is injected into an oil reservoir.

US Pat. No. 5,307,878 likewise discloses a process for tertiary mineral oil production in which foams are used. To stabilize the foam, a substantially non-crosslinked polymer is additionally used. A variety of polymers are mentioned as polymers, for example synthetic polymers such as polyvinyl alcohol, polyethylene oxide, polyvinylpyrrolidone, polyacrylamide, partially hydrolyzed polyacrylamide or natural polymers such as xanthan, scleroglucan, hydroxypropylcellulose or hydroxyethylcellulose.

RU 2 190 091 C2 discloses a multi-stage process for tertiary mineral oil extraction, in which one injects first a polymer solution, then a foam-forming formulation and a gas and then again a polymer solution. The aqueous foam-forming formulation comprises water, alkali, a surfactant and a water-soluble polymer having M _n 300 to 30 000 g / mol. The polymer may be, for example, xanthan, guar gum, polyacrylamide or partially hydrolyzed polyacrylamide.

When separately injecting foam-forming formulations and gases to form foams in the deposit, the gases with the foam-forming formulation must mix with each other after injection into the deposit underground to form a foam. However, a uniform and complete mixing is generally not achievable underground. Rather, as a rule, a considerable part of the foam-forming formulations does not come into contact with the gases, so that no uniform foam bank is formed in the formation. The gases escape mainly to the higher areas of the deposit and the liquid to the lower areas. The mixing of the gases with liquid in storage zones which are relatively far away from the injector (20-100 m), therefore, is hardly possible in the serial pumping of foam-forming formulations and gases. The technique of forming the foam on the surface is complicated, requires additional equipment, and does not guarantee that the foam will reach areas of the deposit farther away from the injector.

Therefore, techniques are known for not injecting gases to form foams but for forming them in situ in the deposit by means of suitable measures.

RU 2 361 074 C2 discloses a process in which an aqueous solution of urea, ammonium nitrate, ammonium thiocyanate and surfactants and, alternately with it, steam is compressed into a crude oil deposit. In the reservoir, the urea hydrolyzes and CO2 and ammonia form in the reservoir, causing an increase in de-oiling.

Bocksermann A., Kocheschkov A., Tarasov A. reveal in "Improvement of Thermal Methods for Degradation of Petroleum Reservoirs", Institute of Scientific and Technical Information Series: Development of Oil and Gas Deposits Volume 24, Moscow 1993 A method of oil extraction The urea is hydrolyzed to CO2 and ammonia under the effect of the reservoir temperature or the steam temperature, and the released gases assist the de-oiling of the oil reservoir.

But even with the methods mentioned foaming is often insufficient. The injected mixture of water and urea, after injection, may mix with reservoir water present in the reservoir and thereby be diluted. As a result, the foaming is difficult and completely prevented by excessive dilution.

The object of the invention was to provide an improved method for the production of oil by means of

To provide foam flooding. Accordingly, a process has been developed for extracting petroleum from a subterranean oil deposit into which at least one production well and at least one injection well have been connected, each associated with the deposit, the process comprising at least one process step (B) of passing petroleum Injection of an aqueous, water-soluble, thickening polymers comprehensive flood medium through the injection well and extraction of petroleum through the production well, the temperature during the process step (B) at least in a portion of the petroleum formation between the injection and the production well at least 60 ° C is and wherein the aqueous flooding medium next to water at least

^■ a glucan (G) with a beta-1, 3-glycosidically linked main chain and beta-1, 6- glycosidically attached side groups, wherein the glucan has a weight average molecular weight M _w of 1, 5 ^* 10 ⁶ 25 ^* 10 ⁶ g / mol, and urea comprises.

List of pictures:

Figure 1 Dependence of the viscosity of the glucan (G) No. P1 and the comparative polymers V1 and V2 on the concentration

Figure 2 Temperature dependence of the viscosity of glucan (G) No. P1 and the

Comparative polymers V1, V2 and V3 in ultrapure water

Figure 3 Temperature dependence of the viscosity of glucan (G) No. P1 and the

Comparative polymers P1, V1, V2 and V3 in reservoir water

Figure 4 Schematic representation of crude oil production by means of the method according to the invention

Figure 5 Schematic representation of crude oil production by means of the method according to the invention after the implementation of measures for Conformance Control.

Figure 6 Formation of CO2 by decomposition of urea in a glucan (G) solution at 90 ° C.

More specifically, the following is to be accomplished for the invention process principle

To carry out the method according to the invention, at least one production well and at least one injection well are sunk into the crude oil deposit. As a rule, a deposit is provided with multiple injection wells and multiple production wells.

Through the injection wells flooding media, such as aqueous flood media or water vapor can be injected into the deposit. As a result of the pressure generated by the pressed-in flooding media, the oil flows in the direction of the production well and is conveyed through the production well. The term "petroleum" in this context, of course, not only means pure phase oil, but the term also includes the usual crude oil reservoir water emulsions.The petroleum may in principle be any kind of crude oil For example, the oil in the reservoir may have a viscosity of at least 30 mPa ^* s (measured at the natural reservoir temperature) Examples of typical cations include Na ⁺ , K ⁺ , Mg ²⁺ or Ca ^2+, and examples of typical anions include chloride, bromide, bicarbonate, sulfate or borate The salinity of the reservoir water may be 20,000 ppm to 350,000 ppm (weight percentages of the sum of all components of the reservoir water), for example 100,000 ppm to 250,000 ppm. The amount of alkaline earth metal ions, in particular of Mg ²⁺ and Ca ²⁺ ions, can be 1000 to 53 000 ppm.

As a rule, reservoir water contains one or more alkali metal ions, in particular Na ⁺ ions. In addition, alkaline earth metal ions may also be present, the weight ratio of alkali metal ions / alkaline earth metal ions generally being> 2, preferably> 3. As anions, at least one or more halide ions, in particular at least chloride ions, are generally present. As a rule, the amount of Ch is at least 50% by weight, preferably at least 80% by weight, with respect to the sum of all anions.

The process according to the invention comprises at least one process step (B) in which an aqueous flooding medium is employed which comprises at least water, a glucan (G) having a β-1,3-glycosidically linked main chain and β-1,6-glycosidically linked side groups and urea. The urea decomposes after injection into the deposit under the influence of the deposit temperature and forms CO2 and NH3. The process may optionally comprise at least one additional process step (A), which is carried out prior to process step (B), and which also injects flood media into the reservoir. The flooding medium is preferably either an aqueous flooding medium (process step (A1)) or steam (process step (A2)).

The process may optionally comprise at least one additional process step (C), which is carried out after a process step (B) and in which flooding media are likewise injected into the reservoir. The flooding medium is preferably either an aqueous flooding medium (process step (C1)) or steam (process step (C2)).

Of course, process step (B) and the optional process steps (A) and (C) can be carried out several times. For example, they can be executed cyclically several times in succession. The method may also optionally include further method steps. This may be a further process step (D). In step (D), a formulation of a thermogel, which is thickened by means of a glucan (G), is injected, ie a formulation which after injection can form highly viscous gels under the influence of the formation temperature. As a result, permeable regions of the formation can be blocked so that subsequently injected aqueous flooding media must flow over new flood paths. This allows more oil to be mobilized.

According to the invention, the temperature during process step (B) at least in a partial region of the petroleum formation between the injection and production well at least 60 ° C, preferably at least 70 ° C, more preferably at least 80 ° C and for example at least 90 ° C. It should not exceed 150 ° C, preferably 135 ° C and more preferably 120 ° C. It may be 60 ° C to 150 ° C, in particular 70 ° C to 140 ° C, preferably 75 ° C to 135 ° C and particularly preferably 80 ° C to 120 ° C. The term "area between the injection and production well" here means that part of the subterranean formation which is detected by the flooding process in the course of process step (B), ie those areas by the flood media injected and / or the oil mobilized thereby during the flooding process Naturally, this is not the shortest route from the injection to the production well, but rather the flow paths are oriented according to the geological conditions in the formation and may therefore be longer The temperature in the entire area of the injection and production well may preferably have the values given above The temperature in the entire area between the injection and production wells should have the abovementioned maximum temperatures of 150.degree , b preferably 135 ° C, and more preferably 120 ° C. The temperatures mentioned may be the natural reservoir temperature. However, the natural reservoir temperature can be changed by process step (B) preceding flooding operations. If, for example, the deposit is flooded with cold water for a long time before carrying out process step (B), the temperature of the deposit is lowered starting from the injection well, with the temperature approaching the natural reservoir temperature with increasing distance from the injection well. On the other hand, if the deposit is flooded with hot steam for a long time before carrying out process step (B), the temperature of the deposit is increased starting from the injection well.

If appropriate, the temperature distribution in the formation can be determined before carrying out process step (B). Methods for determining the temperature distribution of a crude oil deposit are known in principle to the person skilled in the art. The temperature distribution is usually made from temperature measurements at specific points of the formation in combination with simulation calculations, wherein the simulation calculations take into account, inter alia, amounts of heat introduced into the formation and the quantities of heat removed from the formation.

Inventive method

Used glucans

The term "glucans" is understood by the person skilled in the art to mean homopolysaccharides which are composed exclusively of glucose units According to the invention, a particular class of glucans is used, namely glucans comprising a main chain of β-1,3-glycosidically linked glucose units Preferably, the side groups consist of a single β-1, 6-glycosidically linked glucose unit, which, statistically speaking, every third unit of the main chain is connected to another glucose unit β-1, 6 -glykosisch is linked.

Such glucans are secreted by certain fungal strains, and corresponding fungal strains are known to those skilled in the art. Examples include Schizophyllum commune, Sclerotium rolfsii, Sclerotium glucanicum, Monilinia fructigena, Lentinula edodes or Botrytis cinera. Suitable fungal strains are mentioned, for example, in EP 271 907 A2 and EP 504 673 A1, each claim 1. Preferably, the fungi strains employed are Schizophyllum commune or Sclerotium rolfsii, and more preferably Schizophyllum commune, which secretes a glucan, in which every third unit of the main chain is attached to a main chain of β-1,3-glycosidically linked glucose units is linked to another glucose unit β-1, 6-glycosidically; ie, preferably, the glucan is the so-called schizophyllan. The glucans used for the invention have a weight-average molecular weight M _w of about 1.5 to about 25 ^* 10 ⁶ g / mol, in particular 2 to about 15 ^* 10 ⁶ g / mol. The preparation of such glucans is known in principle. For production, the fungi are fermented in a suitable aqueous nutrient medium. The fungi secrete the above-mentioned class of glucans into the aqueous fermentation broth during the fermentation, and an aqueous polymer solution can be separated from the aqueous fermentation broth. Methods for the fermentation of such fungal strains are known in principle to the person skilled in the art, for example from EP 271 907 A2, EP 504 673 A1, DE 40 12 238 A1, WO 03/016545 A2 and "Udo Rau," biosynthesis, production and properties of extracellular fungal glucans ", Habilitation thesis, Technical University of Braunschweig, Shaker Verlag Aachen 1997", which also call suitable culture media. The fermentation plants can be continuous or discontinuous plants.

From the fermentation broth, which contains dissolved glucans and biomass (fungal cells and possibly cell constituents), finally, an aqueous solution containing glucans is separated, leaving an aqueous fermentation broth in which the biomass has a higher concentration than before. The separation can be carried out in particular by means of single or multi-stage filtration or by centrifugation. Of course, several separation steps can be combined.

In the separation, care should be taken that the biomass is retained as completely as possible. In the filtrate remaining biomass can clog fine pores of petroleum formation. The quality of the filtrate can be determined in a manner known in principle by means of the Millipore Filtration Ratio (MPFR value). The measurement specification is described in EP 271 907 B1, page 11, lines 24 to 48.

The MPFR value of the filtrates should be as low as possible, and in particular 1, 001 to 3, preferably 1, 01 to 2.0.

The filtration can preferably be carried out by means of cross-flow filtration, in particular cross-flow microfiltration. The method of cross-flow microfiltration is known in principle to a person skilled in the art and is described, for example, in "Melin, Rautenbach, Membranverfahren, Springer-Verlag, 3rd edition, 2007, page 309 to page 36." The term "microfiltration" is understood by the person skilled in the art to mean the separation of particles of a size between about 0.1 μηη to about 10 μηη. A process for producing glucans using cross-flow filtration is disclosed in WO 201 1/082973 A2. From the resulting filtrate can be separated the glucans. Preferably, however, the glucans are not separated, but the aqueous glucan solution obtained is used directly for the preparation of the flood media for process step (B). The concentration of the glucan solutions obtained can be, for example, 5 to 25 g / l. Solutions of the glucans (G) used according to the invention have a high viscosity even in low concentrations, the viscosity in the temperature range from room temperature to about 140 ° C. largely independent of the temperature and largely independent of the temperature Salinity in the formation water is (see Fig. 2 and Fig. 3). Details on this are shown in the game section.

Flooding medium for process step (B)

In process step (B), an aqueous flooding medium is used which, in addition to water, comprises at least one glucan (G) and also urea.

In addition to water, water-miscible organic solvents may optionally be used in small amounts, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water. Preferably, only water is used as the solvent.

The water may be fresh water or water containing salts. For example, it may be seawater or partially desalinated seawater, or it may be wholly or partially saline reservoir water, which may be injected back into the reservoir in this manner.

The concentration of glucan (G) depends on the desired viscosity of the flooding medium for process step (B). The viscosity of glucan solutions at various concentrations is shown in Figure 1, the dependence of the viscosity on the temperature in Figures 2 and 3.

The viscosity of the aqueous flooding medium for process step (B) depends mainly on the type and concentration of the glucan (G) used. It should be adapted to the viscosity of the oil phase and can be more accurately determined using the ratio (R) between flood medium mobility (M _w ) and oil mobility (MO):

R = M _W / Mo = (krw w) (krw ö), k ™ - relative permeability of the formation for the aqueous flooding medium,

km - relative permeability of the formation for petroleum,

μο - petroleum viscosity,

μ, _Λ , - viscosity of the aqueous flooding medium. μνν refers here to the aqueous flooding medium under conditions of use in the formation. Ideally set to values <1. At R <1 the skilled artisan expects a piston-like displacement of the oil. The optimal ratio (R) between the water mobility (M _w ) and the oil mobility (MÖ) is mostly unavailable, especially for highly viscous oils, because one has to develop unrealistically high injection pressures. One can therefore also work with values R> 1. But even a slight increase in the viscosity of the water phase by means of glucan tends to improve the oil yield. As a rule, the concentration of glucan (G) is 0.1 g / l to 20 g / l, preferably 0.1 to 5 g / l and particularly preferably 0.1 to 2 g / l.

According to the invention, the aqueous formulation furthermore comprises urea.

Urea (H2N-CO-NH2) hydrolyzes in water at elevated temperature to CO2 and ammonia. The hydrolysis reaction is naturally temperature-dependent and proceeds the faster the higher the temperature. If the urea hydrolyzes under the influence of the deposit temperature in the formation, the gases naturally form directly in the formation and thus foams can form in the formation.

The amount of urea in the flooding medium for carrying out process step (B) is generally 15 to 350 g / l of the formulation, in particular 15 g / l to 300 g / l, preferably 30 g / l to 250 g / l and particularly preferred 50 g / l to 250 g / l. Optionally, the formulation may further comprise at least one ammonium salt. Examples of suitable ammonium salts include, in particular, ammonium nitrate and ammonium chloride.

The amount of ammonium salts in the flooding medium for carrying out process step (B) is generally 20 to 300 g / l of the formulation, in particular 20 g / l to 250 g / l, preferably 30 g / l to 250 g / l and particularly preferred 50 g / l to 250 g / l.

Optionally, the formulation may further comprise at least one surfactant. Foaming surfactants are particularly suitable for this purpose. Foaming surfactants have a certain film forming ability and thus promote the formation of foams. Examples of foam-forming surfactants are known in principle to the person skilled in the art. Examples include anionic, cationic or nonionic surfactants, for example sulfates or sulfonates such as alkylbenzenesulfonates, alkoxylated alkylphenols such as alkoxylated nonylphenols.

The amount of surfactants in the flooding medium for carrying out process step (B) is generally 0.1 to 5 g / l of the formulation, in particular 0.5 g / l to 5 g / l, preferably 1 g / l to 5 g / l and more preferably 2 g / L to 5 g / L.

In addition, the formulation for carrying out process step (B) may optionally contain further components, such as, for example, biocides or clay stabilizers.

To prepare the formulation, urea and solid glucan (G) as well as optionally further constituents in water can be dissolved. However, it is advisable to use the above-mentioned aqueous glucan solution obtained from the preparation. The solution can be mixed with the other components in the desired ratio and diluted to the desired concentration. Man can also pre-dissolved the other components, so for example, use an aqueous solution of urea and mix with an aqueous glucan (G) - solution. Execution of process step (B)

To carry out process step (B), said formulation is injected through the at least one injection well into the formation.

The flood medium used for process step (B) is injected into the formation at a temperature of less than 60 ° C., preferably less than 35 ° C., particularly preferably less than 25 ° C. and, for example, about room temperature. The hydrolysis begins with appreciable speed when the urea-containing formulation in the formation has warmed to temperatures of at least 60 ° C. Naturally, the rate of hydrolysis increases with increasing temperature. Preferred temperatures for at least a portion of the petroleum formation between the injection and production wells have already been mentioned above. The formed gases NH3 and CO2 have different effects in the formation. Part of the formed NH3 dissolves in the water forming an alkaline zone and part of the formed CO2 dissolves in the oil and increases its mobility. The remaining amounts of gas form with the components of the formulation for process step (B), ie at least the glucan (G) and optionally the surfactants foams.

The process according to the invention with process step (B) has the advantage that the combination of the temperature- and salt-stable glucan (G) with urea gives positive synergistic effects in the case of the de-oiling. The degree of deoiling is - compared to the water flooding - improved not only in a manner known in principle by the use of thickening acting polymers, but by combining with urea additional effects are achieved.

Hydrolysis of urea in the petroleum formation creates moving zones (banks) enriched with ammonia and CO2. The distribution coefficient of CO2 in the system oil-water is 35 - 100 ° C and 100 to 400 bar at about 4 to 10. Thus, the C0 ₂ accumulates significantly in the oil, and the CO2 of the viscosity of the oil in principle known Way reduced.

Furthermore, neutralization of carboxylic acids occurring in the crude oil, such as, for example, naphthenic acids and ammonia, form in-situ surfactants in the crude oil deposit, which improve the oil formation by reducing the oil-water interfacial tension. Naturally, these surfactant effects are particularly advantageous in petroleum oils with a high carboxylic acid content. In this process variant, it is particularly advantageous to additionally use ammonium salts. The ammonia formed and the ammonium ions form a buffer which keeps the pH in a range which is favorable for the formation of carboxylic acid salts. Finally, foams are formed with the gases formed. The formation of foams is supported by the glucan, because the escape of gases into less deep-lying zones of the oil reservoir is significantly impeded by the viscous polymer solution compared to the use of non-thickened water as a flood. The foam phases have a higher viscosity than the unfoamed water phase, which results in a more uniform flooding. The gas production in the carrier also increases the local formation pressure and thus also supports the oil displacement. Since the unfoamed aqueous urea-glucan solution has a lower viscosity than the foam, the aqueous flooding medium first flows through the highly permeable zones of the formation after injection. After foaming, the flow through the highly permeable zones is made much more difficult.

Additional process step (A)

The process may optionally comprise at least one additional process step (A), which is carried out prior to process step (B), and which also injects flood media through the injection well (s) into the reservoir and removes petroleum through at least one production well.

In one embodiment of the invention, the flooding medium is an aqueous flooding medium (process step (A1)). This may be fresh water or saline water. For example, it may be seawater or partially desalinated seawater, or it may be wholly or partially saline reservoir water, which may be injected back into the reservoir in this manner. In addition to water, water-miscible organic solvents may optionally be used, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water. Preferably, only water is used as the solvent. The injected aqueous flood medium may have a low temperature, for example a temperature in the range of 10 ° C to 35 ° C or about room temperature. Such temperatures usually result automatically, for example, it is the temperature of the seawater used for flooding. But it can also be a warmed aqueous flooding medium. For example, it can be water with a temperature of at least 80 ° C. It can also be overheated water, ie liquid water with a temperature of more than 100 ° C. Naturally, the pressure is higher than 1 bar; Under conditions of injecting into a petroleum formation, a pressure of 1 bar is generally clearly exceeded.

The aqueous flooding medium for process step (A1) may of course also comprise additional components in addition to water or salt water. In particular, additional components may be thickening components, in particular thickening polymers. This may preferably be a glucan (G). The viscosity of a glucan-containing aqueous flooding medium should in this case preferably be such that the viscosity of a flooding medium injected in a process step (A1) is lower than the viscosity of the aqueous flooding medium injected in subsequent process step (B).

In a further embodiment of the invention, the injected flooding medium may be steam (process step (A2)). Water vapor may have a temperature of more than 300 ° C when injected into the oil reservoir. Additional process step (C)

The process may optionally comprise at least one additional process step (C) which is carried out after a process step (B) and which also injects flood media through the injection well (s) into the reservoir and removes petroleum through at least one production well.

In one embodiment of the invention, the flooding medium is an aqueous flooding medium (process step (C1)). This may be fresh water or saline water. For example, it may be seawater or partially desalinated seawater, or it may be wholly or partially saline reservoir water, which may be injected back into the reservoir in this manner.

In addition to water, water-miscible organic solvents may optionally be used, but at least 85% by weight, preferably at least 95% by weight, of the solvents used should be water. Preferably, only water is used as the solvent.

The injected aqueous flood medium may have a low temperature, for example a temperature in the range of 10 ° C to 35 ° C or about room temperature. But it can also be a warmed aqueous flooding medium. For example, it may be

Water at a temperature of at least 80 ° C act. It can also be overheated water, ie liquid water with a temperature of more than 100 ° C. Naturally, the pressure is higher than 1 bar; Under conditions of injecting into a petroleum formation, a pressure of 1 bar is generally clearly exceeded.

The aqueous flooding medium for process step (C1) may of course also comprise additional components in addition to water or salt water. In particular, additional components may be thickening components, in particular thickening polymers. This may preferably be a glucan (G).

The viscosity of a glucan-containing aqueous flooding medium should in this case preferably be such that the viscosity of a flooding medium injected in a process step (C1) is higher than the viscosity of the injected in step (B) aqueous flooding medium.

In a further embodiment of the invention, the injected flooding medium may be water vapor (process step (C2)). Water vapor may have a temperature of more than 300 ° C when injected into the oil reservoir.

Combinations of Process Steps (A), (B) and (C) Process steps (A), (B) and (C) may be combined with each other. The combination may, for example, be one of the following flow diagrams 1 to 4.

Flood Scheme 1: Process Step (A1)> Process Step (B) -> Process Step (C1)

Aqueous medium Aqueous medium

Flooding Scheme 2: Process Step (A2)> Process Step (B)> Process Step (C2)

Steam steam

Flooding Scheme 3: Process Step (A2)> Process Step (B)> Process Step (C1)

Water vapor Aqueous medium

Flooding scheme 4: Process step (A1)> Process step (B)> Process step (C2)

Aqueous medium water vapor

Furthermore, the sequence of method steps (A) -> (B) -> (C) can also be repeated cyclically one after the other.

Flooding Scheme 1 In Flood Scheme 1, flooding is first carried out with an aqueous flooding medium as described above, then flooding is continued with the flooding medium (B) comprising glucan and urea and finally flooded again with an aqueous flooding medium.

In this embodiment, the natural reservoir temperature should be at least 60 ° C, preferably at least 70 ° C, more preferably at least 80 ° C, and for example at least 90 ° C. It may be 60 ° C to 150 ° C, in particular 70 ° C to 140 ° C, preferably 75 ° C to 135 ° C and particularly preferably 80 ° C to 120 ° C.

If in step (A2) cold flood water, so for example flood water is used with a temperature in the range of 10 ° C to 35 ° C, namely, the temperature of the crude oil deposit in the environment injection point gradually decreases over time. Flooding a reservoir with water can take months or even years. Naturally, the cooling at the injection site itself is greatest, and with increasing distance from the injector the temperature approaches the natural reservoir temperature again. A sufficient natural reservoir temperature ensures that the actual reservoir temperature, as required to carry out the process, is at least 60 ° C, at least in a portion of the petroleum formation between the injection and production wells.

If you want to avoid cooling or at least too great a cooling, you can heat the aqueous flooding medium of the injection, for example, to temperatures of at least 80 ° C.

In a preferred embodiment, flooding in process step (C1) with a flooding medium which is thickened, preferably also with the aid of glucan (G). The amount of glucan (G) should in this case be such that the viscosity of the aqueous flooding medium injected in process step (C1) is greater than the viscosity of the aqueous flooding medium injected in process step (B). Such a measure counteracts the effect of "fingering." "Fingering" means that a lower viscosity flooding phase does not form a uniform flow front to a higher viscous flooding phase, but that the flow front is uneven. This is mainly due to the fact that the lower-viscosity flood phase flows faster through permeable zones, while less permeable zones flow through more slowly. "Fingering" can largely be avoided if the subsequent flooding phase is more viscous.

In a further preferred embodiment, both in method step (A1) and in method step (C1), flooding is carried out with an aqueous flooding medium which are thickened, preferably in each case with the aid of a glucan (G), the viscosity of the flooding phase used being in the order (A1 ) -> (B) -> (C1) increases.

Flood Scheme 2 In Flood Scheme 2, flooding is first carried out with steam as described above, then flooding is continued with the flooding medium (B) comprising glucan and urea, and finally flooded with steam again.

In this embodiment, the natural reservoir temperature may also be less than 60 ° C. By injecting the water vapor in process step (A) - the water vapor used for injecting typically has temperatures of up to 300 ° C, the deposit heats up from the injection well with increasing duration of steam injection, so that at least in a portion of the petroleum formation between the injection and the production well a temperature of at least 60 ° C, preferably at least 70 ° C, more preferably at least 80 ° C and for example at least 90 ° C is achieved. However, it should reach 150 ° C., preferably 135 ° C. and more preferably 120 ° C. If these values are exceeded, before starting process step (B), an intermediate flooding with cold water, for example, water at temperatures of 10 ° C to 35 ° C take place.

Subsequently, process step (B) is carried out. The duration of process step (B) may be determined by the skilled person depending on the desired results, but at the latest when the temperature in the entire region of the petroleum formation between the injection and the production well has fallen to temperatures of less than 60 ° C, process step (B ) stopped. It is advisable to stop process step (B) even when the temperature falls below 70.degree. C., particularly when the temperature falls below 80.degree.

The process is then continued with the injection of steam (process step (C2)). In order to protect the flood phase (B), it may also be advisable to carry out an intermediate flooding with cold water before injecting the steam. The intermediate tide may also be thickened, preferably with the help of a glucan (G). If thickening is used, the viscosity of the intermediate flood should be at least as high as that of the flooding phase used for process step (B).

Flood Scheme 3 Flood Scheme 3 initially floats with water vapor as described above, then flooding with the flocculant (B) comprising glucan and urea, and then flooding is continued with an aqueous flooding medium. The temperature of the natural deposit can also be lower than 60 ° C in flood scheme 3, as in flood scheme 2, because the deposit warms up under the influence of water vapor. With regard to the details of steps (A2) and (B), what has been said in flood scheme 2 applies. Following process step (B), process step (C1) is carried out.

Flood Scheme 4 Flood Scheme 4 is first flooded with an aqueous flooding medium as described above, then flooding is continued with the flooding medium (B) comprising glucan and urea, and finally flooded with steam. As in Flood Scheme 1, the natural reservoir temperature must be at least 60 ° C. Preferred temperature ranges have already been mentioned in flow diagram 1. It may also be useful in flood scheme 4 to flood after process step (B) with cold water-if necessary, thickened water between.

Additional Process Step (D) By means of the additional process step (D), the process according to the invention can be combined with measures for "Conformance Control". In oil reservoirs with particularly heterogeneous permeability, injected aqueous flooding media or else steam preferably flow through the particularly permeable regions of the formation, which are thereby preferably de-oiled, while less permeable regions are flowed through with little or no flow. Thus, un mobilized oil will remain in the less permeable areas. This is shown schematically in Figure 4. An injection well (1) and two production wells (2, 2 ') were drilled into an oil reservoir. Through the injection well (1), the aqueous flooding medium for process step (B) is injected, flows in the direction of the production wells (2, 2 ') and thereby presses the petroleum in front of him. The so-called displacement wave (ie the boundary between the aqueous phase and the petroleum phase) is shown schematically (7). The preferred flood paths (3) for the aqueous phase or the mobilized petroleum are shown hatched. These are not straightforward but follow the permeable zones of the formation. Outside the shaded area unimmobilized oil remains. Also marked is the 60 ° C isotherm (4). Within the marked zone it is colder, outside the zone it is warmer. In the areas with a temperature above 60 ° C, the urea begins to hydrolyze and, accordingly, the foaming begins.

In step (D), according to the invention, a formulation of a thermogel, which is thickened by means of a glucan (G), is injected, ie a formulation which after injection can form highly viscous gels under the influence of the formation temperature. The formulation comprises at least one glucan (G), urea and at least one water-soluble aluminum (III) salt and / or a partially hydrolyzed aluminum (III) salt. The water-soluble aluminum (III) salts may be, for example, aluminum chloride, aluminum bromide, aluminum nitrate, aluminum sulfate, aluminum acetate or aluminum acetylacetonate. But it can also be already partially hydrolyzed aluminum (III) salts, such as aluminum hydroxychloride. Of course, mixtures of several different aluminum compounds can be used. The pH of the formulation should be <5, preferably <4.5 and more preferably <4. Aluminum (III) salts are acidic, so that this pH is usually set alone if Al (III) is sufficient. If necessary, ewtas could be acidified. It is preferably aluminum (III) chloride and / or aluminum (III) nitrate.

The active principle of such thermogels is that the said aluminum (III) salts form acidic solutions, but form sparingly soluble gels in the alkaline range. The change in pH is triggered by the hydrolysis of urea at elevated temperatures, in which, as already described, ammonia forms.

An amount of from 0.2 to 3% by weight of aluminum (III) based on the aqueous formulation has proven useful, and the amount of urea should be such that 3 mol of base per mole of Al (III) are liberated. The rate of gel formation naturally depends on the temperature, because the urea hydrolyzes faster and faster with increasing temperature. Furthermore, the rate of yellowing may depend on the ratio of aluminum (III) to urea. Details of this are summarized in the examples section.

When hotter zones are reached, the aluminum-urea-glucan formulations form sparingly soluble gels. This is shown schematically in Figure 5; Here are yellow banks (5) formed. The previous preferred flood zones are thereby blocked and subsequently injected flood medium is forced to flow through less permeable, not yet de-oiled zones to the formation. These new flood paths are shown in Figure 5 with the arrows (6). This can mobilize more oil.

The thickening of the aluminum urea solution with the glucan has the effect that due to the increased viscosity, the injected formulation does not mix so easily with the reservoir water and previously injected flooding phase (B) (suppressing or at least reducing fingering). If thinning is too high, it would not be possible to form a highly viscous gel.Through thickening, the flood with the thermogel can run through longer stretches of the formation without being diluted too much thus blocking the formation at these locations

Of course, the method may optionally include further method steps. On the one hand, this includes the already mentioned intermediate flooding with water between the process steps (A) and (B) and / or (B) and (C). Furthermore, the process can also be combined with surfactant floods. In surfactant flooding, an aqueous formulation of surfactants is injected into the formation, which surfactants reduce the water-oil interfacial tension after injection. Suitable surfactants for use in oil deposits are known in the art and are also commercially available. Surfactant flooding can advantageously be carried out before carrying out process step (B). A possible sequence of procedural steps would be, for example, process step (A1) -> surfactant flooding -> process step (B)> optional process step (C).

The following examples are intended to explain the invention in more detail: Preparation of glucan (G):

Glucan (G) having a β-1,3-glycosidically linked main chain and β-1,6-glycosidically linked side groups (according to the invention)

The glucan (G) was prepared by means of in WO 201 1/082973 A2, Inventive Example 1, pages 15 to 16 in the described apparatus. The concentrate obtained was diluted to the particular desired temperature for the experiments. Comparative Polymer 1:

Commercially available, synthetic polymer of about 75 mol% of acrylamide and 25 mol% of the sulfonic acid group-containing monomer 2-acrylamido-2-methylpropane-sulfonic acid (Na salt), weight average molecular weight Mw of about 1 1 million g / mol

Comparative Polymer 2:

Commercially available biopolymer xanthan (CAS 1 1 138-66-2) biopolymer, prepared by fermentation with the bacterium Xanthamonas campestris) having a weight-average molecular weight M _w of about 2 million g / mol.

Comparative Polymer 3: Commercially available biopolymer Diutane (biopolymer prepared by fermentation with Sphingomonas sp.)

The glucan according to the invention and the comparison polymers were used to carry out the viscosity measurements described below. Execution of the viscosity measurements:

Measuring instrument: shear stress controlled.it physica MCR301 rotational viscometer

Pressure cell with double-gap geometry DG 35 / PR / A1 Measuring range: 25 ° to 170 ° C, as indicated

Shear rate: as indicated

The complete measuring system, including the syringe used to draw the sample and place it in the rheometer, was purged with nitrogen. During the measurement, the measuring cell was exposed to 8 bar of nitrogen.

Experimental series 1: The viscosity of solutions of glucan (G) (referred to in Figure P1) and comparative polymers V1 and V2 was measured at various concentrations of 0.2 g / l to 2 g / l. The measurements were carried out in synthetic reservoir water. For this purpose, the polymers are dissolved in excessively concentrated salt water or, if the polymer already exists as a solution, a solution of the polymer is mixed with excessively concentrated salt water and the resulting salt solution is subsequently diluted to give the concentrations emitted at the bottom. The measurements of P1 and V2 were carried out at 54 ° C and the measurement V1 at 40 ° C. Composition of reservoir water (per liter):

CaCl ₂ 42600 mg

MgCl ₂ 10500 mg

NaCl 132000 mg

Na ₂ SO ₄ 270 mg

NaB0 ₂ ^* 4 H ₂ 0 380 mg

Total salinity 185750 mg

The results are shown in Figure 1. Figure 1 shows that glucan P1 achieves the best viscosity efficiency in reservoir water, i. the samples give the highest viscosity at a given concentration.

Test Series 2 There was the viscosity of aqueous solutions of the glucan (G) No P1 and the comparative polymers V1, V2 and V3 in high-purity water in a concentration of 3 g / l at a shear rate of 100 sec ^_1 in the temperature range of 25 ° C. measured up to 170 ° C. For this purpose, the solution of gluacan (G) No. P1 was diluted accordingly, and the polymers V1, V2 and V3 were dissolved in the corresponding concentration in water. The samples were injected at room temperature into the measuring cell and the heating rate was 1 ° C / min. The results are shown in Figure 2.

Series 3: The procedure was as in test series 1, except that not the ultrapure water but a synthetic reservoir water was used to prepare the solutions. The results are summarized in Figure 3.

Comment on test series 2 and 3:

The experiments show the advantages of the glucan (G) No. P1 used according to the invention in comparison to the comparison polymers V1, V2 and V3 at high temperature and high salt concentration. The viscosity of glucan (G) No. P1 remains constant in saline water as well as in ultrapure water at temperatures of 25 to 140 ° C and only then slowly begins to decrease. In ultrapure water both the synthetic polymer V1 (copolymer of acrylamide and 2-acrylamido-2-methylpropane-sulfonic acid) and the biopolymer V3 show a similar behavior, while the biopolymer V2 is significantly worse. In reservoir waters, however, all comparative polymers V1, V2 and V3 are worse than the glucan P1 at higher temperatures. Gas formation by decomposition of urea

Figure shows the formation of gas bubbles of CO2 of an aqueous solution of about 1, 5 g / l glucan (G), 20 wt.% Urea and 3 wt. % HCl when thermostating the solutions at 90 ° C. The figure shows gas formation after 1, 2 and 3 h.

Formulations for Process Step (D)

For the optional process step (D), formulations of water, urea and aluminum salts are used.

In Table 1 below, the time until gel formation for a mixture of 8 wt.% AICI 3 (calculated as anhydrous product, corresponds to 1, 6 wt.% Al (III)), 25 wt.% Urea and 67 wt. Water shown.

Table 1: Time to gelation at different temperatures

In Table 2 below, the time to gelation for various mixtures of AICI3 (calculated as anhydrous product), urea and water at 100 ° C and 100 ° C is shown. It can be seen that as the amount of urea decreases, the time to form the gel becomes longer and longer.

Table 2: Time to gelation ("-" no measurement).

Claims

claims

1 . A method of extracting oil from a subterranean oil deposit into which at least one production well and at least one injection well each associated with the deposit are associated, the process comprising at least one process step (B) comprising injecting an aqueous , promotes water-soluble, thickening polymers comprising flood medium through the injection well and extraction of petroleum through the production well, characterized

the temperature during the process step (B) is at least 60 ° C. at least in a partial region of the oil formation between the injection and the production well, and the aqueous flood medium is at least next to water

^■ a glucan (G) with a beta-1, 3-glycosidically linked main chain and beta-1, 6- glycosidically attached side groups, wherein the glucan has a weight average molecular weight M _w of 1, 5 ^* 10 ⁶ 25 ^* 10 ⁶ g / mol, as well as

^■ includes urea.

2. The method according to claim 1, characterized in that the aqueous flooding medium used in step (B) comprises 15 to 300 g / l urea and 0.1 to 5 g / l of glucan (G).

3. The method according to claim 2, characterized in that the aqueous flooding medium used in step (B) additionally comprises 50 to 250 g / l of an ammonium salt

4. The method according to claim 2 or 3, characterized in that the aqueous flooding medium used in step (B) additionally comprises 0.1 to 5 g / l of a surfactant.

5. The method according to any one of claims 1 to 4, characterized in that the temperature is at least in a partial region of the petroleum formation between the injection and the production well at least 80 ° C.

6. The method according to any one of claims 1 to 4, characterized in that the temperature is at least in a partial region of the petroleum formation between the injection and the production bore 80 ° C to 120 ° C.

7. The method according to any one of claims 1 to 6, characterized in that the method comprises an additional process step (A), which is carried out before step (B), and in which either an aqueous flooding medium (step (A1)) or water vapor (Step (A2)) injected.

8. The method according to any one of claims 1 to 7, characterized in that the method comprises an additional process step (C), which is carried out after process step (B), and in which either an aqueous flooding medium (process step (C1)) or water vapor (Step (C2)) injected.

9. The method according to claim 7, characterized in that it is process step (A1), wherein the injected aqueous flood medium in addition to water at least one glucan (G), with the proviso that its amount of glucan (G) is so dimensioned in that the viscosity of the aqueous flooding medium injected in process step (A1) is lower than the viscosity of the aqueous flooding medium injected in process step (B).

10. The method according to claim 8, characterized in that it is process step (C1), wherein the injected aqueous flooding medium in addition to water comprises at least one glucan (G), with the proviso that its amount of glucan (G) is so dimensioned in that the viscosity of the aqueous flooding medium injected in process step (C1) is greater than the viscosity of the aqueous flooding medium injected in process step (B).

1 1. Method according to one of claims 7 to 10, characterized in that in the process steps (A1) and / or (C1) injected aqueous flooding media have a temperature of at least 80 ° C.

12. The method according to claim 7, characterized in that in step (A) either water vapor or an aqueous flooding medium having a temperature of at least 80 ° C is injected, and further comprising between the process steps (A) and (B) an aqueous flooding medium injected at a temperature of less than 40 ° C.

13. The method according to claim 8 or 12, characterized in that in step (C) either water vapor or an aqueous flooding medium having a temperature of at least 80 ° C is injected, and that further between the process steps (B) and (C ) injected an aqueous flooding medium at a temperature of less than 40 ° C.

14. Process according to claim 12 or 14, characterized in that the aqueous flooding media injected between (A) and (B) and / or (B) and (C) comprise at least one glucan (G).

15. A process according to any one of claims 1 to 14, characterized in that the process comprises at least one additional process step (D) for blocking highly permeable regions of the subterranean petroleum formation, and in which an aqueous

Flood medium injected, which next to water at least • a glucan (G) with a beta-1, 3-glycosidically linked main chain and beta-1, 6- glycosidically attached side groups, wherein a weight average molecular weight M glucan _w of 1, 5 ^* 10 ⁶ 25 ^* 10 ⁶ g / mol,

• Urea, as well

• at least one water-soluble aluminum (III) salt and / or a partially hydrolyzed aluminum (III) salt.

A method according to claim 15, characterized in that one carries out method step (D) after process step (B) and then the process continues with a new execution of process step (B).