CN114555753A

CN114555753A - Biopolymers for enhanced hydrocarbon recovery

Info

Publication number: CN114555753A
Application number: CN202080070107.7A
Authority: CN
Inventors: A·凯撒; M·扎夫热尔; M·卡伦; H·迪茨; A·科尔; A·P·德奥利维拉·菲略; M·弗休尔斯唐克; J·怀尔德
Original assignee: Clariant International Ltd
Current assignee: Clariant International Ltd
Priority date: 2019-10-03
Filing date: 2020-10-01
Publication date: 2022-05-27
Also published as: BR112022006166A2; MX2022003893A; CA3151818A1; WO2021064131A1

Abstract

The present invention generally relates to methods of treating a wellbore or a subterranean hydrocarbon-bearing formation to enhance hydrocarbon production from the formation. In particular, the present invention relates to polymers for use in oil and gas field applications, such as enhanced hydrocarbon production in oil reservoirs having high temperatures. The present invention relates to a method for treating a subterranean formation, and in particular to a method and system for recovering hydrocarbons, especially oil, from an oil-bearing subterranean formation or reservoir, wherein a biopolymer is applied in tertiary recovery of the hydrocarbons.

Description

Biopolymers for enhanced hydrocarbon recovery

The present invention generally relates to methods of treating a wellbore or a subterranean hydrocarbon-bearing formation to enhance hydrocarbon production from the formation. In particular, the present invention relates to polymers for use in oil and gas field applications, such as enhanced hydrocarbon recovery in oil reservoirs having high temperatures. The present invention relates to a method for treating a subterranean formation, and in particular to a method and system for recovering hydrocarbons, especially oil, from an oil-bearing subterranean formation or reservoir, wherein a biopolymer is applied in tertiary recovery of the hydrocarbons.

The production and production of crude oil from a subterranean reservoir may include three distinct stages, namely primary, secondary and tertiary production. During primary production, the natural pressure of the reservoir drives the oil outflow in conjunction with, for example, a pump that brings the oil to the surface. However, during primary production, typically only about 10% of the reservoir's original oil is produced in situ. Secondary recovery techniques are typically based on the injection of water or gas to maintain pressure and displace the oil and drive it out to the production side, resulting in the in situ recovery of another 5% to 25% of the original oil. In addition, several tertiary or enhanced oil recovery techniques have been developed which offer the prospect of producing up to 10% or even more of the reservoir's original oil in situ.

Tertiary oil recovery (also referred to as "enhanced oil recovery") encompasses a number of different technologies, such as gas injection technology, chemical injection technology, ultrasonic stimulation, microbial injection technology, or thermal recovery (which includes circulating steam and steam flooding).

In chemical injection, a water-soluble polymer having a high molecular weight is generally used to increase the viscosity of the aqueous phase. In aqueous solutions, such polymers are capable of providing various viscosity levels through entanglement and/or inter-chain hydrogen bonding interactions. The effect of increasing the viscosity of the injected water is to improve zonal cleanup of the reservoir by reducing the mobility difference between the water and oil phases, resulting in reduced "channeling". Thus, oil contained in the subterranean formation may be produced more efficiently and more quickly.

Synthetic high molecular weight polymers based on specific monomers and having various structures have been found to be particularly effective at relatively low dosage rates. The most effective chemical identified in the industry is synthetic Partially Hydrolyzed Polyacrylamide (PHPA). Partially hydrolyzed polyacrylamides and copolymers containing partially hydrolyzed polyacrylamide moieties are widely used because these polymers allow for beneficial distribution of anionic groups in the polymer backbone and have low polydispersity. These types of polymers are known to be very effective for low salinity and moderate temperatures. However, they are often inadequate for temperatures above 80 ℃ and increased levels of divalent ions such as calcium and magnesium. Due to the anionic nature of the carboxylate groups, this type of polymer may interact with divalent ions present in the treatment fluid in the formation fluid, respectively. Above a certain level of anionic properties and in the presence of higher amounts of divalent ions, the polymer may precipitate out of solution, thus losing its viscosity modifying properties originally imparted to the treatment fluid. In addition, degradation of the polymer, for example by thermal, free radical, mechanical and/or biological reaction mechanisms, can affect the viscosity of the treatment fluid. Mechanical and biological degradation can generally be prevented by careful selection of surface equipment, by adjusting the molecular weight of the polymer and/or by co-injection of biocides. Radical degradation can be prevented mainly by the addition of protective chemicals. The thermal stability of the polymer can be improved to some extent by chemical modification of the polymer and/or the polymer chemistry itself. However, in general the stability of the polymer is insufficient for the temperatures and exposure times required for the production process which may lead to poor viscosity and poor performance. Thus, insufficient thermal stability often results in a reduction in the viscosity of the treatment fluid in the formation and prevents satisfactory oil production by such EOR techniques, especially at higher formation temperatures, prolonged exposure, and/or when the brine used is significantly salted.

To overcome the inadequate performance of synthetic polymers, especially in high temperature and high salinity environments, biopolymers have been proposed for enhanced oil recovery applications. In particular, biopolymers produced by certain microorganisms exhibit a significant viscosifying effect even at lower concentrations than synthetic polymers. They do not degrade in the presence of cations such as magnesium and calcium and are stable at higher temperatures than synthetic polymers. During enhanced oil recovery operations, the polymer may remain in the subterranean formation and thus may experience degradation conditions for months, sometimes in excess of 6 months. Thus, the polymer must not degrade or only slightly degrade over time in order to retain its viscosifying properties in order to push the oil up from the injector to the production well.

WO 2017/214492a2 teaches a pumpable and/or flowable β -glucan suspension which achieves the desired filterability and viscosity build for enhanced oil recovery applications. The described beta-glucans include polysaccharides classified as 1,3 beta-D-glucans, i.e. any polysaccharide having a beta- (1,3) -linked backbone of D-glucose residues and modifications thereof. Fungal strains secreting such glucans are known to the person skilled in the art. Examples include Schizophyllum commune (Schizophyllum commune), Sclerotinium rolfsii (Sclerotinium rolfsii), Sclerotinium gluglucosicum (Sclerotinium glucanum), Monilina fructicola (Monilinla fructicola), Lentinus edodes (Lentinula edodes) or Botrytis cinerea (Botryges cinerea). The fungus strain used is preferably Schizophyllum commune or Sclerotinia sclerotiorum. Examples of such 1,3 β -D-glucans include curdlan (a homopolymer of β - (1,3) -linked D-glucose residues produced by e.g. Agrobacterium spp.), grifolan (a branched β - (1,3) -D-glucan produced by e.g. fungal grifola frondosa), lentinan (a branched β - (1,3) -D-glucan produced by e.g. fungal lentinus edodes having two glucose branches linked at every five glucose residues of the β - (1,3) -backbone), Schizophyllan (a branched β - (1,3) -D-glucan produced by e.g. fungal Schizophyllan (Schizophyllan) having one glucose branch for every three glucose residues in the β - (1,3) -backbone), Sclerotinia sclerotiorum (branched β - (1,3) -D-glucan produced by, for example, the fungus Sclerotium spp., one of the three glucose molecules of the β - (1,3) -backbone of which is linked to a pendant D-glucose unit by a (1,6) - β linkage), SSG (highly branched β - (1,3) -glucan produced by, for example, the fungus Sclerotinia sclerotiorum), soluble glucan from yeast (β - (1,3) -D-glucan produced by, for example, Saccharomyces cerevisiae, having β - (1,6) -linked pendant groups), laminarin (β - (1,3) -glucan produced by brown algae, having β - (1,3) -glucan and β - (1,6) -dextran side groups) and cereal glucans such as barley beta-glucan (linear beta- (1,3) (1,4) -D-glucan produced by e.g. barley, oats or wheat). Preferably, 1,3-1,6 β -D-glucans, i.e. β -glucans comprising a backbone of glucose units derived from β -1, 3-glycosidic linkages and side groups formed from and bonded to the glucose units, and modifications are used.

SPE-185326-MS teaches the production of pullulan from Aureobasidium Pullulans (Aureobasidium Pullulans) and the use of this pullulan in enhanced oil recovery operations. This reference applies a growth medium for aureobasidium pullulans with a high dry matter content. The high dry matter content results in the Aureobasidium pullulans fungus producing pullulan instead of beta-glucan.

What is needed is an additional polymer useful in enhanced oil recovery operations that provides improved performance over known polymers.

Various aspects of the disclosure are provided in the following claims, which may be combined in any number and in any combination not logically or technically inconsistent to provide additional embodiments of the disclosure.

The present inventors have noted significant problems with prior art polymers for oil recovery operations: they tend to have significantly reduced viscosity at elevated reservoir temperatures.

As described in detail below, the present inventors have determined that certain polymers produced by fermentation of ascomycota organisms may provide improved properties, particularly properties useful in oil recovery operations such as enhanced oil recovery operations. In certain aspects, the present disclosure provides polymers useful in oil recovery operations that exhibit relatively constant viscosity over a wide range of elevated reservoir temperatures. For example, in certain aspects, the polymers of the present disclosure exhibit good viscosity properties at temperatures of at least 120 ℃ (248 ° F), such as in the range of 120 ℃ to 160 ℃, or in the range of 120 ℃ to 150 ℃. Furthermore, in certain aspects, the polymers of the present disclosure are tolerant to high salinity, for example, greater than 40000ppm, particularly greater than 150000ppm Total Dissolved Solids (TDS).

The present inventors have surprisingly found that novel polysaccharide polymers according to the present disclosure can provide aqueous solutions having significantly higher viscosities at a given polymer dose rate (and thus the same viscosities at lower polymer dose rates) compared to other biopolymers according to the prior art. This is especially pronounced at high temperatures above 120 deg.C, for example in the range of 120-160 deg.C or 120-150 deg.C. In addition, the polymers according to the present disclosure do not show thermal degradation even at high temperatures above 90 ℃ and even above 120 ℃ over extended residence times, and therefore exhibit a reduced degree of undesirable viscosity reduction compared to that observed for prior art polymers. In certain aspects of the present disclosure, the polymer substantially retains its viscosifying properties at elevated temperatures. Thus, oil and/or gas may be more efficiently pushed at low shear rates, thereby increasing production rates. Another advantage of the polysaccharide polymers according to certain aspects of the invention is their shear-thinning effect: at the high shear rates typically applied during pumping of polymer solutions into the formation, the viscosity approaches that of water, which limits the impact on pumping capacity.

Accordingly, one aspect of the present disclosure provides the use of a β -glucan polysaccharide biopolymer for recovering oil from a subterranean formation. Another aspect of the disclosure provides a method for recovering oil from a subterranean formation, the method comprising injecting into the formation an aqueous composition comprising a polysaccharide, wherein the aqueous composition is injected into the subterranean formation through at least one injection borehole and crude oil is removed from the subterranean formation through at least one production borehole. In the uses and methods according to these aspects of the present disclosure, the β -glucan polysaccharide biopolymer is obtained by a method for fermentation of ascomycota, the method comprising the steps of:

a) providing a culture medium having a dry matter content selected from the range of 0.1 to 0.3 wt.%, said culture medium containing less than 0.2 wt.% of organic nitrogen (i.e. nitrogen from an organic nitrogen source);

b) selecting at least one fungus belonging to Ascomycota from 0.05g_CDWL to 50g_CDWInoculation density in the range of/L inoculates the medium;

c) adding at least one carbon source in a concentration of 1 to 20 wt.%;

d) mixing the medium according to step d) and the at least one fungus for a period of time of 24 to 400 hours;

e) removing 30 to 90 weight percent of the culture medium and the at least one fungus;

f) adding 30 to 90% by weight of a culture medium as defined in step a) of the method;

g) repeating steps c) to f)2 to 100 times;

wherein at least one of steps c) to g) is carried out at a relative gas content selected from 0.005 to 0.5.

Hereinafter, various elements of the uses, methods and materials of the present disclosure will be described in more detail. These elements are listed with the detailed description, however, it should be understood that they may be combined in any manner and in any number to produce additional embodiments. The various described examples and embodiments should not be construed as limiting the scope of the disclosure to only the explicitly described embodiments. The present disclosure should be understood to support and encompass embodiments combining the explicitly described embodiments with any number of the disclosed elements. Moreover, any arrangement or combination of all the elements described in this disclosure should be considered disclosed by the description of the present application, unless the context indicates otherwise.

Throughout the specification and claims, unless the context requires otherwise, the word "comprise", and variations such as "comprises" and "comprising", will be understood to imply the inclusion of a stated member, integer or step, or group of members, integers or steps, but not the exclusion of any other member, integer or step, or group of members, integers or steps. The use of the terms "a" and "an" and "the" and similar references in the context of describing various elements of the disclosure (especially in the context of the claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range. Unless otherwise indicated herein, each individual value is incorporated into the specification as if it were individually recited herein. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. The use of any and all examples, or exemplary language (e.g., "such as," "specifically," "in certain embodiments") provided herein, is intended merely to better illuminate the invention and does not pose a limitation on the scope of the disclosure and appended claims. No language in the specification should be construed as indicating any non-claimed element as essential to the practice of the disclosed use, method, or material.

In the present disclosure, the term "ascomycota" is understood to include any fungus belonging to the phylum ascomycota classification or. Ascomycota belongs to the subkingdom Bikaryotes (Dikarya). Ascomycota suitable for use in the process of preparing the biopolymers described herein include, but are not limited to, any fungus falling within the polyspora class such as aureobasidium (aureobasidioidea). The method of producing a biopolymer described herein is particularly useful when the species of the phylum ascomycota is Aureobasidium pullulans, also known as Aureobasidium oleae, azymeniandida malolacta, Candida malolacta, cladosporium pullulans, demadium pullulans, exobasidium vitas, hormonema oleae, hormonema pullulans, pullulan (pullulan fermentation), pullulan schoeniii species (pullulan fermentation). The foregoing species are understood to be synonyms. Fungi belonging to the phylum Ascomycota are commonly referred to as Ascomycetes.

The culture medium provided in step a) of the method described herein is characterized by a dry matter content selected from the group consisting of 0.1 to 0.3 wt. -%, preferably 0.15 to 0.25 wt. -%, e.g. 0.10 to 0.25 wt. -% or 0.15 to 0.30 wt. -%. The term "dry matter content" refers to the mass determined after removal of water and other volatile compounds from a medium sample using an IR-balance. In the present invention, the dry matter content may also be referred to as "dry weight".

At least one of steps c) to g) of the process as described above is carried out using a relative gas content selected from 0.005 to 0.5, wherein a range of 0.0075 to 0.40 and 0.01 to 0.35 is also within the scope of the invention.

In the present invention, the relative gas content rG is defined by the following formula:

wherein

P is the input power W,

V_Lis added in steps b) and c) and contains at least one fungus and at least oneVolume of culture Medium a) for the seed carbon sources [ m ]³]，

ρ_LIs the density [ kg/m ] of the medium according to step a)³]The culture medium contains the at least one fungus and the at least one carbon source added in steps b) and c), and

u_Gis the apparent gas velocity [ m/s ]]。

The relative gas contents are described in Liepe, Verfahrenstehnisch Berechnngmethoden Teil 4: Stoffvereinigen in fluiden Phasen-Ausruhungen und ihre Berechannen von einem Autorenktiv un Federf ü hrung von F.Liepe, Leipzig, VEB Deutscher Verlag fur Grundstoffindustrie (1988), the entire contents of which are incorporated herein by reference.

In the present disclosure, the term "power input" P is defined as

Wherein

Ne is a number of Newton's,

ρ_Lis a medium [ kg/m ] according to step a)³]The density of the at least one fungus and the at least one carbon source added in steps b) and c),

n is the frequency [ s ] of the stirrer^-1]，

d is the diameter [ m ] of the stirrer, and

η is the viscosity of the medium according to step a) containing the at least one fungus and the at least one carbon source added in steps b) and c).

In the present invention, the term superficial gas velocity is defined as

Wherein

Q_GIs the volume gas flow [ m³/s]By air, at least one fungus and at least one fungus sprayed into the culture medium per second is understoodVolume of carbon source

Dr is the inner diameter of the vessel.

The culture medium may be provided in any vessel known to the skilled person to be suitable for the process of the present invention, such as a batch or fed-batch reactor, a gas lift reactor, a stirred tank reactor or a bubble column reactor. In certain embodiments of the present disclosure additionally described herein, the absolute pressure in the headspace of the container is in the range of 1 to 11 bar, preferably in the range of 2 to 10 bar, more preferably in the range of 3 to 9 bar, especially in the range of 4 to 8 bar, e.g. in the range of 1 to 10 bar, in the range of 1 to 9 bar, in the range of 1 to 8 bar, in the range of 2 to 11 bar, in the range of 2 to 9 bar, in the range of 2 to 8 bar, in the range of 3 to 11 bar. In the range of 3 to 10 bar, in the range of 3 to 8 bar, in the range of 4 to 11 bar, in the range of 4 to 10 bar or in the range of 4 to 9 bar. In certain embodiments of the present disclosure as further described herein, the vessel is equipped with a light source that provides a light intensity of at least 300Lux when placed on the surface of the fermentation medium during at least 40% of the time as described in step d). 1Lux is defined as 1 lumen/m²。

In step b) of the process for the preparation of biopolymers described herein, the medium is inoculated with at least one fungus belonging to the phylum ascomycota. "inoculation" can be carried out by any method known to the person skilled in the art to be suitable for this process, for example by adding at least one fungus in purified form or in precultured form. In the methods described herein, the concentration of the at least one fungus is selected from 0.05g_CDWL to 50g_CDWThe range of/L. For example, in certain embodiments further described herein, the concentration is preferably 0.07g_CDWFrom L to 25g_CDW/L, more preferably 0.08g_CDWL to 20g_CDWL, especially 0.09g_CDWL to 15g_CDWL, e.g. 0.05 to 25g_CDW0.05 to 20 g/L_CDW0.05 to 15 g/L_CDW0.07 to 50 g/L_CDW0.07 to 15 g/L_CDW0.08 to 50 g/L_CDW0.08 to 25 g/L_CDW0.08 to 15 g/L_CDW0.09 to 5,/L0g_CDW0.09 to 25 g/L_CDWOr 0.09 to 20g_CDWAnd L. Thus, the dimension "L" relates to the volume of the culture medium according to step a) of the method described herein.

The at least one fungus used in the methods described herein is, for example, only one single type of fungus or a mixture of different fungi, e.g., a mixture of two, three, or four different fungi. The term "dry cell weight" (CDW) is understood to mean the weight of the total biomass divided by the volume of the fermentation sample after centrifugation of the fermentation sample, removal of the supernatant, washing with 9g/L NaClA solution, centrifugation again, removal of the supernatant again and drying at 90 ℃ until a constant weight is reached.

In the present disclosure, the term "preculture" is understood to comprise any composition of the fermentation or culture medium used for preculture of at least one fungus. The term "preculture" is well known to anyone skilled in the art of fermentation. In a particular embodiment, the at least one fungus is pre-cultured to a dry cell weight of 2g before being added to the culture medium according to step b) of the method of the invention_CDWL to 30g_CDWAnd L. It is noteworthy that in the methods described herein, high yields of β -glucan can be obtained while keeping the volume of the pre-culture used relatively low, since for example the use of 0.1 to 0.5 wt% (pre-culture weight to medium weight) may be sufficient.

In certain desirable embodiments of the methods further described herein, the nitrogen content of the medium from the organic nitrogen source according to step a) is selected from the range of 0.003 to 0.02 wt.%, for example the range of 0.005 to 0.015 wt.% or 0.006 to 0.01 wt.%.

In certain desirable embodiments of the methods further described herein, step b) is performed for a period of time from 1 minute to 8 hours, such as a period of time from 2 minutes to 7 hours, from 3 minutes to 6 hours, or from 5 minutes to 5 hours.

In step c) of the method as further described herein, at least one carbon source is added at a concentration of 1 to 20 wt.%. In certain embodiments further described herein, the at least one carbon source is preferably added at a concentration of 2 to 18 wt.%, more preferably at a concentration of 3 to 15 wt.%, particularly at a concentration of 4 to 12 wt.%, for example at a concentration of 1 to 18 wt.%; or at a concentration of 1 to 15 wt.%; or at a concentration of 1 to 12 wt.%; or at a concentration of 2 to 20 wt.%; or at a concentration of 2 to 15 wt.%; or at a concentration of 2 to 12 wt.%; or at a concentration of 3 to 20 wt.%; or at a concentration of 3 to 18 wt.%; or at a concentration of 3 to 12 wt.%; or at a concentration of 4 to 20 wt.%; or at a concentration of from 4 to 18% by weight or at a concentration of from 4 to 15% by weight, all relative to the combined mass of the medium a), the respective fungus and its preculture and carbon source. The "addition" can be carried out by any method known to the person skilled in the art to be suitable for this process. Step c) may be performed after step b) of the process, but may also be performed before step b), or steps b) and c) may also be performed simultaneously. In another embodiment of the present disclosure, steps a) and c) may be performed simultaneously and may be performed prior to step b).

In step d) of the method as described herein, the medium and the at least one fungus are mixed for a period of time of from 24 to 400 hours. In certain embodiments, the culture medium is mixed with at least one fungus, preferably for a period of time of 30 to 350 hours, more preferably for a period of time of 35 to 300 hours, most preferably for a period of time of 40 to 250 hours, and in particular for a period of time of 50 to 200 hours, for example for a period of time of 24 to 350 hours; or a period of 24 to 300 hours; or a period of 24 to 250 hours; or a period of 24 to 200 hours; or a period of 30 to 400 hours; or a period of 30 to 300 hours; or a period of 30 to 250 hours; or a period of 30 to 200 hours; or a time period of 35 to 400 hours; or a period of 35 to 350 hours; or a period of 35 to 250 hours; or a period of 35 to 200 hours; or a period of 40 to 400 hours; or a period of 40 to 350 hours; or a period of 40 to 300 hours; or a period of 40 to 300 hours; or a time period of 50 to 400 hours; or a period of 50 to 350 hours; or a time period of 50 to 300 hours; or a period of 50 to 250 hours. "mixing" can be performed by any method known to those skilled in the art to be suitable for use in the methods described herein.

In certain embodiments as further described herein, a method that has been shown to have particular advantages with respect to time and energy consumption is mixing by continuously pumping the medium and at least one fungus from the bottom to the top of the vessel.

In a particularly advantageous embodiment of the process further described herein, the mixing is performed without using any kind of rotating device, such as a stirrer. One such advantageous system for carrying out the process described herein is, for example, a bubble column reactor.

In certain embodiments of the methods further described herein, the mixing can be at 2 to 12000W/m³Specific power input P/V, e.g. 100 to 1000W/m³Is carried out at a specific power input of (1).

In stirred mixing systems, such as stirred tank reactors, the term "specific power input" is to be understood as meaning

Wherein

P is the input power W,

ne is a Newton number < - >,

ρ is the density [ kg/m ] of the medium according to step a) containing the at least one fungus and the at least one carbon source added in steps b) and c)³]，

n is the stirrer frequency [ s ]^-1]，

d is the diameter [ m ] of the impeller,

eta is the viscosity of the medium, the carbon source and the at least one fungus, and

v is the volume of the medium, the carbon source and the at least one fungus according to step a).

In systems without any type of impeller or agitator, such as bubble column reactors, the specific power input is understood to mean that

Wherein g is the acceleration of gravity [ m s^-2]And u and_gis the superficial gas velocity as defined above.

In certain embodiments as further described herein, mixing is performed until the culture medium and the at least one fungus are 20 seconds during step d)^-1The shear rate and the dynamic viscosity at a temperature of 20 ℃ are in the range of 40 to 600mPas, for example, in the range of 50 to 550mPas, 70 to 500mPas, 100 to 450mPas and 130 to 400 mPas.

In certain particular embodiments further described herein, the pH is maintained throughout the process in the range of 4.0 to 6.0, such as in the range of 4.25 to 5.75, 4.25 to 5.5, and 4.25 to 4.75. In certain embodiments further described herein, the pH is maintained above 4.75, for example in the range of 4.75 to 5.25, throughout the process by the addition of a base, wherein the base can be any base known to a skilled person trained in fermentation skills to be suitable for fermentation and free of nitrogen, such as sodium hydroxide or potassium hydroxide. A particular advantage of certain methods described herein is that the use of acids to adjust pH levels is not required.

In certain particular embodiments as further described herein, the temperature is maintained in the range of 22 to 30 ℃ throughout the process, e.g., in the range of 23 to 30 ℃, in the range of 24 to 29 ℃, and in the range of 24 to 28 ℃.

In step e) of the method described herein, 30 to 90% by weight of the culture medium and the at least one fungus are removed. In certain embodiments further described herein, 40 to 85 wt.%, 45 to 80 wt.%, 50 to 75 wt.%, or 55 to 65 wt.% of the culture medium and the at least one fungus are removed. Thus, "removing" can be performed by any means and method known to those skilled in the art to be suitable for use in the methods described herein.

In step f) of the method as described herein, 30 to 90 wt% of the medium as defined in step a) is added to the remaining medium and the at least one fungus, for example in the range of 40 to 85 wt%, 45 to 80 wt%, 50 to 75 wt% or 55 to 65 wt% of the medium. Thus, "addition" can be made by any means and methods known to those skilled in the art to be suitable for use in the methods described herein. It is therefore important that the amount of removed medium and fungus is substantially equal to the amount of fresh medium, wherein deviations of up to 30%, preferably less than 10%, are tolerable.

In step g) of the methods described herein, steps c) to f) are repeated 2 to 100 times, for example 2 to 80 times, 2 to 70 times, 2 to 50 times and 2 to 25 times. One particular advantage of the methods described herein is that up to 100-fold more cells and fermentation products can be harvested without the need for new inoculation. The fermentation processes and medium compositions described herein can provide high yields of β -glucan biopolymers. The repetition of steps c) to f) is particularly advantageous, since the yield of β -glucan biopolymer increases significantly with the first repetition. Furthermore, since cleaning of the reactor is only necessary after step g) of the process is completed, the cleaning expenditure can be minimized, contributing to further cost savings. The cost of preparing the preculture can be minimized since preculture preparation only needs to be performed in every 2 to 100 iterations of the method. In addition, production equipment downtime (non-production phase) is minimized because production can be kept running without loss of time for harvesting, sterilization, cleaning, and filling.

The following detailed description defines embodiments that are particularly advantageous for the production of β -glucan biopolymers from fungi belonging to the genus aureobasidium. These embodiments are not meant to limit the scope of the present application in any respect.

Embodiment a: a process for fermenting aureobasidium sp comprising the steps of:

a) providing a culture medium having a dry matter content selected from the range of 0.1 to 0.3 wt% and containing less than 0.2 wt% of an organic nitrogen source;

b) at least one fungus belonging to the species aureobasidium pullulans is selected from 0.05g_CDWL to 50g_CDWInoculating the medium at an inoculation density in the range of/L;

c) adding at least one carbon source in a concentration of 1 to 20 wt.%;

g) repeating steps c) to f)2 to 100 times;

Embodiment B: a process for fermenting aureobasidium sp comprising the steps of:

b) selecting at least one fungus belonging to the species Aureobasidium pullulans from 0.05g_CDWL to 50g_CDWInoculating the culture medium at an inoculation density in the range of L;

c) adding sucrose at a concentration of 1 to 20 wt%;

g) repeating steps c) to f)2 to 100 times;

wherein at least one of steps c) to g) is carried out at a relative gas content selected from the range of 0.005 to 0.2.

Embodiment C: a process for fermenting aureobasidium sp comprising the steps of:

b) selecting at least one fungus belonging to the species Aureobasidium pullulans from 0.05g_CDWL to 50g_CDWInoculation Density in the/L rangeInoculating the culture medium;

c) adding sucrose at a concentration of 1 to 20 wt%;

g) repeating steps c) to f)2 to 100 times;

wherein at least one of steps c) to g) is carried out at a relative gas content selected from the range of 0.005 to 0.2 and at a temperature of 24 to 30 ℃ and at a pH of 4 to 6.

Embodiment D: a process for fermenting aureobasidium sp comprising the steps of:

b) selecting at least one fungus belonging to the species Aureobasidium pullulans from 0.05g_CDWL to 50g_CDWInoculating the medium at an inoculation density in the range of/L;

c) adding sucrose at a concentration of 1 to 20 wt%;

g) repeating steps c) to f)2 to 100 times;

wherein at least one of steps c) to g) is carried out at a relative gas content selected from the range of 0.005 to 0.2 and at a temperature of 24 to 30 ℃ and at a pH of 4 to 6, and step b) is carried out for a period of 1 to 6 hours before step c).

Other embodiments of biopolymers useful for the uses and methods as described herein are described in the two european patent applications attached as appendices, each by reference for all purposes and as described herein.

It should be understood that when reference is made hereinafter to "oil" or "oilfield applications," similar considerations apply to "hydrocarbon" production, i.e., oil and gas applications.

As described above, the methods of the present disclosure produce a β -glucan polysaccharide biopolymer. These polymers have a polymer backbone of β -1, 3-D-glucose residues, one β -1, 6-D-glucose side chain per three backbone residues, and a weight average molecular weight in the range of 1000000-. The biopolymer is not crosslinked. Polysaccharide biopolymers are nonionic in nature. Notably, the present inventors have determined that polysaccharide biopolymers prepared according to the methods described herein can exceed the performance of thickeners such as xanthan gum, guar gum and cellulose derivatives, as well as the performance of sulfate, sulfonate and quaternary ammonium surfactants. Aqueous solutions of biopolymers can be highly shear thinning, can maintain viscosity at elevated temperatures, and can have satisfactory flow through porous media, and can therefore have novel structural behavior in flow.

Uses of the polymers of the present disclosure for enhanced oil recovery include use in unconventional reservoirs. In general, an unconventional reservoir is essentially any reservoir that requires special production operations outside of conventional operational practices. Unconventional reservoirs include reservoirs such as tight gas sands, gas and oil shales, coal bed gas, heavy oil and tar sands, and gas hydrate deposits. These reservoirs lack the petrophysics of conventional reservoirs and must be somehow stimulated to increase the conductivity of the pores. Thus, these reservoirs often require the use of specific production solutions, such as stimulation treatments or steam injection. Stimulation treatments are typically performed on oil and gas wells in low permeability reservoirs. Specially designed fluids are pumped at high pressure and high velocity into the reservoir interval to be treated, causing vertical fractures to open.

Conventional reservoirs are typically composed of porous and permeable sandstone or carbonate rock, which produces oil and/or gas by displacing hydrocarbons from the pore space.

As noted above, the polymers described herein may be used in treatment fluids for hydrocarbon recovery applications, particularly oilfield applications. According to one embodiment of the use and method further described herein, the polymer is preferably comprised in the solution or treatment fluid in an amount of from 25 weight-ppm to 10000 weight-ppm, more preferably from 250 weight-ppm to 7500 weight-ppm, particularly preferably from 500 weight-ppm to 5000 weight-ppm. The term "treatment fluid" in the meaning of the present invention refers to a solution or suspension for use in hydrocarbon recovery applications, such as oilfield applications. The fluids other than the polymers of the present invention may contain other additives or components. The fluid may use water as a solvent, one or more organic solvents (e.g., alcohols), or a combination thereof. Parts per million (ppm) relates to the amount of polymer relative to the total weight of the treatment fluid comprising the polymer. In the following, further aspects and embodiments of the invention are described:

it is particularly preferred according to the present invention that the polymer in aqueous solution provides a filtration ratio of not more than 1.5. A filtration ratio greater than 1.5 indicates clogging of the filter paper pores due to inhomogeneity of the polymer solution. Having a filtration ratio of the polymer of less than or equal to 1.5 indicates limited clogging of the filter paper pores. A filtration ratio of no greater than 1.5 indicates the ability to obtain a homogeneous aqueous polymer solution that does not plug the filter and therefore will experience fewer injectivity problems when encountering tight pores in a subterranean hydrocarbon formation during enhanced oil recovery operations. It is assumed that the formation pores have a minimum size of 5 μm, which means that if particles present are smaller than the minimum pore size, the polymer is considered suitable for enhanced oil recovery operations. The "filtration ratio" (FR) according to the present disclosure is determined by a test as described herein, which involves injecting an aqueous polymer solution through a filter paper of 1.2 μm pore size at constant pressure. FR is determined by dividing the measured difference between the time at 200mL minus the time at 180mL by the difference between the time at 80mL minus the time at 60mL according to the following formula:

(FR)＝(t₂₀₀-t₁₈₀)/(t₈₀-t₆₀)

wherein

t₂₀₀Time required to obtain 200ml of filtrate under constant pressure

t₁₈₀Time required to obtain 180ml of filtrate under constant pressure

t₈₀Time required to obtain 80ml of filtrate under constant pressure

t₆₀Time required to obtain 60ml of filtrate under constant pressure

The polymers described herein may be provided in the form of powders, inverse emulsions, aqueous-in-water dispersions, microbeads, polymer solutions, and dried forms thereof.

The polymers described herein may be obtained as suspensions, inverse emulsions (i.e., emulsions of hydrophilic polymers in organic solvents), powders, or any other liquid or solid form. The liquid form may use water as a solvent, an organic solvent (e.g., ethanol), or a combination thereof. According to the invention, it is particularly preferred to obtain or provide the polymers according to the invention as powders or inverse emulsions.

The polymers as described herein may be suitable for use in treatment fluids, for example as a conformance improving additive, a drilling fluid additive, or a fracturing fluid additive, for example as a guar gum substitute.

In certain desirable embodiments of the present disclosure, the polymers as described herein are used in treatment fluids for the recovery of oil from subterranean formations, particularly for Enhanced Oil Recovery (EOR) operations. In such applications, the treatment fluid injected into the formation exhibits improved thermal resistance and, therefore, improved viscosity stability during fluid propagation.

It has been shown that treatment fluids containing polymers as described herein can be used in any chemical injection technique known to those skilled in the art. It is well known in the art how to apply polymer-containing solutions to tertiary oil recovery techniques, for example for displacing oil. In tertiary recovery, injection of the polymer according to the present disclosure may trap free or emulsified water present in the oil. The method can reduce the mobility of water without compromising the flow of oil. In addition, it may increase the ratio of oil to water in the produced fluid. Furthermore, when an alkaline or alkaline-surfactant-polymer (ASP) is used as a tertiary oil recovery technology, the use of the polymers of the present disclosure for tertiary oil recovery may allow for the production of oil in the presence of impurities such as surfactants and caustic (sodium hydroxide, sodium orthosilicate, or sodium carbonate) that are typically present in oil. The reaction of these caustic materials used in current tertiary oil recovery with natural surfactants (e.g., naphthenic acids) present in the oil often has a negative impact on subsequent steps in the production process of the oil (e.g., demulsification process). The generation of fines is another risk associated with caustic or alkaline-surfactant-polymer (ASP) processing. The use of materials and methods may ameliorate these risks.

Notably, the materials of the present disclosure can have good performance at alkaline pH, as described below. Thus, in certain embodiments of the uses and methods as further described herein, the polysaccharide is provided to an aqueous phase in an oil-bearing formation having a pH of at least 8 or at least 8.5, for example in the range 8 to 10.5, or 8 to 10, or 8 to 9.5, or 8 to 9, or 8.5 to 10.5, or 8.5 to 10, or 8.5 to 9.5.

As noted above, the uses and methods described herein are particularly applicable to so-called "tertiary" or "enhanced" mining methods. One of the most common methods is based on injecting water into the reservoir through dedicated injection wells. This is commonly referred to as secondary recovery (i.e., primary recovery of oil produced by natural pressure in the formation). When the water content in the produced fluid becomes too high, secondary recovery is stopped. Additional oil may be displaced from the subterranean formation by using tertiary or Enhanced Oil Recovery (EOR) techniques. These techniques include thermal techniques, non-thermal techniques such as electrical techniques, miscible techniques, steam techniques or even chemical techniques for enhanced production of oil left in place. In the context of the present invention, the term "oil" includes any type of oil, including light oil, heavy oil or even bitumen oil. As noted above, gas may also be produced using the materials and methods described herein. The materials and methods described herein are most preferably useful in tertiary oil recovery techniques (chemically enhanced oil recovery) involving the injection of polymers in the form of dilute solutions or treatment fluids. Generally, the efficiency of chemical treatment by addition of the polymers of the present disclosure is improved relative to water injection. By "thickening" the injected water, improved sweep efficiency and control over the mobility between oil and water-based fluids in the subterranean formation is provided for more rapid and efficient recovery of oil.

The treatment fluid to be injected into a subterranean formation according to the use and method contains the polymers of the present disclosure, and optionally it may contain other chemical compounds useful for enhanced oil recovery. Suitable treatment fluids include water (e.g., fresh water, brine (saltwater), brine (brine), seawater) and optionally non-aqueous fluids (e.g., oxygenated solvents, hydrocarbon solvents, etc.). The polymers of the present invention may be present in any suitable concentration. Preferably, the polymer of the present invention is present in an amount of 20ppm to 20000ppm, more preferably in an amount of 50 to 10000ppm, especially preferably in an amount of 100 to 5000ppm, for example in an amount of 20 to 10000ppm, or in an amount of 20 to 5000ppm, or in an amount of 50 to 20000ppm, or in an amount of 50 to 5000ppm, or in an amount of 100 to 20000ppm, or in an amount of 1000 to 10000ppm, based on the total weight of the treatment fluid.

Preferably, the viscosity of the treatment fluid incorporating the polymer of the present invention is in the range 50cP to 2000cP, preferably in the range 100cP or 1000cP, more preferably in the range 200cP to 600 cP. Under the same conditions, incorporation or use of the polymers of the present disclosure can result in an increase in viscosity of at least 10%, preferably at least 25%, even more preferably at least 50%, as compared to the viscosity of a treatment fluid without the polymer. For example, in certain embodiments as otherwise described herein, the polysaccharide is provided to the oil-bearing formation in the form of a treatment fluid having a viscosity at a temperature of 25 ℃ and at a constant temperature for 10s according to rotational rheology^-1Is at least 10%, at least 25%, or even at least 50% higher than the viscosity of a fluid of the same composition as the treatment fluid but without the polysaccharide.

The treatment fluids of the present invention employing the polymers of the present disclosure may further contain other additives and chemicals known to those skilled in the art to be commonly used in oilfield applications. These include, but are not necessarily limited to, materials such as surfactants, high temperature fluid stabilizers (e.g., sodium thiosulfate, mercaptobenzothiazole (mercaptobenzothiazole), thiourea), oxygen scavengers (e.g., sulfite), alcohols (e.g., isopropanol), scale inhibitors, corrosion inhibitors, fluid loss additives, bactericides, stabilizers, deoxidizers, precipitants, radical scavengers, sacrificial agents, and complexing agents.

In preferred embodiments of the uses and methods further described herein, the polysaccharide biopolymer is used in combination with one or more biocides. Preferred biocides are glutaraldehyde, glyoxal, tetrakis (hydroxymethyl) phosphonium sulfate, 1, 3-dimethylol-5, 5-dimethylhydantoin, and peracetic acid. This combination has proven to be particularly beneficial for enhanced oil and/or gas recovery, as the present inventors have found that the presence of biocides does not significantly affect the viscosifying properties of the polymers of the present disclosure.

A surfactant or surfactant may be added to the fluid. Surfactants, solvents and co-solvents may be included, for example to optimize oil recovery by changing interfacial tension and thereby increasing the amount of oil that can be pushed out by the polymer solution. Other chemical compounds or additives that may be included in the treatment fluid may include weak, strong or ultra-strong inorganic or organic bases capable of saponifying crude oil and producing surfactant species for emulsifying the oil in situ. These include, for example, sodium carbonate, caustic soda, borate and metaborate compounds, amines, and basic polymers. At all shear rates, water itself has a viscosity of 1cP, which is typically much lower than the viscosity of oil in a subterranean formation. Addition of the polymers of the present disclosure to the aqueous phase can increase the viscosity of the water to between 0.1 and 1 second^-1A target viscosity in the range of 50% -100% of the viscosity of the particular oil phase at low shear rates in the range, which represents the shear rate typically observed during traversing the reservoir from an injection well to a production well. By increasing the viscosity, the injected water is "thickened" to improve displacement efficiency and control mobility between the oil and water-based fluids in the formation for faster and more efficient recovery of oil. In 10-100 seconds^-1And higher shear rates above, the viscosity of solutions of the polymers of the present disclosure is low, in the range of 1-10 cP. In addition, the polymers of the invention may have a higher viscosity at high temperatures than at low temperatures under the same conditionsAnd (4) degree. To maintain low injection pressures to prevent pumping problems during injection, low viscosities approaching that of water at the high shear rates and low ambient temperatures experienced during pumping and application are advantageous.

The uses, methods, and materials described herein are further illustrated below by several examples, which are not intended to limit the scope or spirit of the present disclosure.

Examples

The following polymers were tested under the specific conditions described below to demonstrate the viscosification of the polymers of the present disclosure at high temperatures.

Test polymers: the polymers of the present disclosure are derived from the fermentation of sucrose by aureobasidium according to the methods described herein.

Xanthan gum: 1500000-2000000Da molecular weight structures form rigid rods with high hydrodynamic volume in solution due to the formation of multi-stranded helices with negatively charged pyruvate side chains wrapped around the molecular backbone.

Scleroglucan: a nonionic molecule of 1000000-1500000Da molecular weight consisting of a backbone of D-glucopyranose units having β -1,3 linkages, with every third backbone unit having β -1, 6-linked D-glucopyranose side chain units. The molecule is a rod-like triple helix chain that behaves as a semi-rigid molecule in aqueous solution.

Pullulan: a linear water-soluble polysaccharide comprising predominantly maltotriose units linked by α -1,6 glycoside units.

300ppm, 500ppm and 1000ppm of the respective polymers were dissolved in deionized water, saline solution "Johan Sverdrup saline" or saline solution "Peregrino saline" or North sea water. The composition and salt concentration of each brine are listed below.

Salt water composition

After dissolution, the Anton Paar MCR 302 rheometer was used at 25 ℃ and 83 ℃ for 0.1 second with a double gap measurement system^-1To 100 seconds^-1The viscosity of each polymer solution was measured over a range of shear rates. The data obtained are shown in figures 1 to 9.

FIG. 1: the viscosity of the polymers of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate for 300ppm of the polymer of the present disclosure in deionized water.

FIG. 2: the viscosity of the polymers of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate for 500ppm of the polymer of the present disclosure in deionized water.

FIG. 3: the viscosity of the polymers of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate for 1000ppm of the polymer of the present disclosure in deionized water.

Table 1: 300ppm, 500ppm, and 1000ppm of the polymers of this disclosure in deionized water at 25 ℃ and 83 ℃ in 0.1 second^-1To 100 seconds^-1Viscosity data over a range of shear rates

FIG. 4: viscosity of the polymer of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate for 300ppm of the polymer of the present disclosure in Johan Sverdrup brine.

FIG. 5: viscosity of the polymer of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate for 500ppm of the polymer of the present disclosure in Johan Sverdrup brine.

FIG. 6: viscosity of the polymer of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate relationship for 1000ppm of the polymer of the present disclosure in Johan Sverdrup brine.

Table 2: viscosity data for 300ppm, 500ppm, and 1000ppm of the inventive polymers in Johan Sverdrup brine at 25 ℃ and 83 ℃

FIG. 7: viscosity of the polymer of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate for 300ppm of the polymer of the present disclosure in Peregrino brine.

FIG. 8: viscosity of the polymer of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate for 500ppm of the polymer of the present disclosure in Peregrino brine.

FIG. 9: viscosity of the polymer of the present disclosure at 25 ℃ and 83 ℃. Viscosity versus shear rate relationship for a polymer of the present disclosure at 1000ppm in Peregrino brine.

Table 3: 300ppm, 500ppm and 1000ppm of the polymer of the invention in Peregrino brine at 25 ℃ and 83 ℃ in the shear rate range 0.1 second^-1To 100 seconds^-1Viscosity data within the range

Core displacement injection test

In the following, reference is made to core displacement injection tests, which demonstrate the propagation of the polymers of the invention in representative sandstone formation rocks. In a core displacement injection test, fluid is injected into jacketed reservoir core reservoir rock and differential pressure is measured from the inlet and outlet. The baseline differential pressure was measured by injecting brine in the core displacement apparatus. After the brine injection, a target concentration of polymer in the brine is injected and the differential pressure using the polymer is measured and compared to a baseline differential pressure measured by injecting the brine. High pressure differentials indicate flow resistance due to plugging or coating of the surface area of the rock bore.

The baseline differential pressure in the following data was measured by injecting 1 pore volume of Peregrino brine through sandstone reservoir rock at 55 ℃. The pore volume is defined as the ratio of the volume of air in the porous material to the total volume of the material, i.e. here the volume of air in the sandstone reservoir rock divided by the volume of sandstone reservoir rock. The polymer of the present disclosure was then injected into sandstone reservoir rock at 500ppm in Peregrino brine at 55 ℃. The respective data are shown in fig. 10. After an initial peak in the pressure differential due to iron deposits in the sandstone rock being pulled out and flowing through with the polymer of the present invention, the pressure differential returns to only slightly above the baseline Peregrino brine pressure differential, indicating the ability of the polymer of the present disclosure to propagate through the reservoir rock without depositing on or plugging the rock pores. Without wishing to be bound by theory, the inventors speculate that during injection, shear thinning of the polymers of the present disclosure allows for relatively low injection pressures that are only slightly above the baseline brine.

FIG. 10: a Peregrino brine was injected at 55 ℃ and then 500ppm of the polymer of the present disclosure in the Peregrino brine was injected into the sandstone reservoir rock in the core flood, the differential pressure measured over time.

In the following, reference is reflected in the measurement of the viscosity curves of the polymers of the present disclosure and the comparative polymers at 1000ppm in northern sea saline at 83 ℃ and in deionized water at 20 ℃.

At an ambient temperature of 20 ℃ for 0.01 second^-1To 100 seconds^-1The viscosity of a solution of the polymer of the present disclosure is similar to the viscosity of a comparative xanthan polymer solution at 1000ppm in deionized water at the same concentration. At 20 ℃ for 0.1 second^-1To 100 seconds^-1The viscosity of the polymer solutions of the present disclosure is higher than the viscosity of the comparative scleroglucan polymer solution and the pullulan reference solution within the shear rate range of (a). The respective data are shown in fig. 12, 13 and 15.

At elevated temperatures representing specific reservoir conditions in the north sea of 83 ℃, the viscosity of the solutions of the polymers of the present disclosure is higher than all comparative polymer solutions: the xanthan polymer solution, the comparative scleroglucan polymer solution, and the pullulan reference solution were used at the same concentrations in north sea brine. Thus, lower concentrations of the polymers of the present disclosure are needed to achieve the target viscosity in saline as compared to the comparative xanthan or pullulan polymers. Notably, the polymers of the present disclosure retain viscosity in the presence of salt ions relative to comparative scleroglucan and pullulan polymers. The respective data are shown in fig. 12, 14 and 16.

FIG. 11: in 0.01 to 100 seconds^-1The viscosity of the polymers of the present disclosure in deionized water at 20 ℃ versus shear rate compared to xanthan control polymer is within the shear rate range.

FIG. 12: in 0.01 to 100 seconds^-1Polymers of the present disclosure paired with xanthan gum over a range of shear ratesViscosity versus shear rate in north sea brine at 83 ℃ compared to polymer.

FIG. 13: in 0.01 to 100 seconds^-1The viscosity of the polymers of the present disclosure in deionized water at 20 ℃ versus shear rate of the scleroglucan control polymer.

FIG. 14: in 0.01 to 100 seconds^-1In the shear rate range, the polymers of the present disclosure have a viscosity to shear rate relationship in north sea saline at 83 ℃ compared to the scleroglucan control polymer.

FIG. 15: in 0.01 to 100 seconds^-1The viscosity versus shear rate of the polymers of the present disclosure in deionized water at 20 c compared to the reference pullulan control polymer.

FIG. 16: in 0.01 to 100 seconds^-1Compared to the reference pullulan control polymer, the viscosity versus shear rate relationship in north sea brine at 83 ℃ of the polymer of the present disclosure was determined.

Table 4: viscosity data of the polymers of the present disclosure and comparative xanthan and scleroglucan polymers at different temperatures. At 0.1 second^-1To 100 seconds^-1Within the shear rate range, 1000ppm polymer viscosity in north sea brine at 83 ℃ and deionized water at 20 ℃.

Considering now viscosity as a factor in changing the production of oil from a well, the mobility equation can be considered to show the importance of polymers to change the viscosity of brine and thus the mobility of oil in the formation. Considering mobility (M) as the effective permeability (K) of rock to fluid i_i) And viscosity (μ) of the fluid_i) Function of (c):

the mobility ratio (M) of displacement is the mobility of the displacement fluid divided by the mobility of the displaced fluid. And fluidity can be expressed in a simplified manner as:

m ═ k/. mu.saline/(k/. mu.oil)

For example, if the fluidity is 1, then there is a neutral effect; water and oil flow in the well as well. If the fluidity is <1, the oil flows more easily than water, and thus there is a favorable yield. If the mobility >1, water will flow more readily than oil, and the well will have an unfavorable oil production.

In this embodiment, if the viscosity (μ) of the brine is, for example, the same as that of the oil, and all other factors of the equation remain constant, then M ═ 1, and the oil and brine production will not change.

On the other hand, if the viscosity of the brine is increased, for example by a factor of 5, while keeping the viscosity of the oil constant and also keeping all other factors of the equation constant, the value of the fluidity will be lower than zero, and in this case the oil production will be advantageous.

Figure 17 shows how the viscosity of the polymer of the present disclosure can increase the viscosity of brine (here up to 3-fold) when compared to existing solutions of polyacrylamide (HPAM) that is partially hydrolyzed at a temperature of 120 ℃.

FIG. 17: rheology of the polymers of the present disclosure compared to HPAM at 100psi and 120 deg.C

In another set of experiments, 10s^-1The viscosity of an aqueous solution of 2000ppm of polymer (polymer of the present disclosure, CBP, compared to xanthan and HPAM) in oilfield brine was tested at a temperature range of 20 ℃ to 180 ℃. Some experiments were performed at pH 8.5.

The results are shown in FIG. 18.

Notably, the polymers of the present disclosure exhibit lower temperature sensitivity than the comparative polymers. The polymers of the present disclosure exhibit a low degree of temperature sensitivity even under alkaline pH conditions.

Claims

1. Use of a polysaccharide for recovering oil from a subterranean formation, wherein the polysaccharide is obtained by a process for fermenting ascomycota, the process comprising the steps of:

a) providing a culture medium having a dry matter content selected from the range of 0.1 to 0.3 wt% and containing less than 0.2 wt% of nitrogen from an organic nitrogen source;

b) selecting at least one fungus belonging to Ascomycota from 0.05g_CDWL to 50g_CDWInoculating the culture medium at an inoculation density in the range of L;

c) adding at least one carbon source in a concentration of 1 to 20 wt.%;

g) repeating steps c) to f)2 to 100 times;

2. A method for recovering oil from a subterranean formation, the method comprising injecting an aqueous composition comprising a polysaccharide into the formation, wherein the aqueous composition is injected into the subterranean formation through at least one injection borehole and crude oil is withdrawn from the subterranean formation through at least one production borehole, wherein the polysaccharide is obtained by a method for fermenting ascomycota, the method comprising the steps of:

a) providing a culture medium having a dry matter content selected from the range of 0.1 to 0.3 wt% and containing less than 0.2 wt% nitrogen from an organic nitrogen source;

b) selecting at least one fungus belonging to Ascomycota from 0.05g_CDWL to 50g_CDWInoculating the medium at an inoculation density in the range of/L;

c) adding at least one carbon source in a concentration of 1 to 20 wt.%;

g) repeating steps c) to f)2 to 100 times;

3. The use or method of any one of the preceding claims, wherein the nitrogen content of the medium according to step a) is selected from the range of 0.003 wt.% to 0.02 wt.%.

4. The use or method of any preceding claim, wherein the pH is maintained in the range of 4.0 to 6.0.

5. Use or method according to any one of the preceding claims, wherein the temperature T is maintained in the range of 22 to 30 ℃.

6. The use or method according to any of the preceding claims, wherein the dynamic viscosity of the medium during step d) is selected from the range of 40 to 600 mPas.

7. The use or method according to any one of the preceding claims, wherein step b) is carried out for a period of from 1 minute to 8 hours.

8. Use or method according to any one of the preceding claims, wherein the Ascomycota species is Aureobasidium pullulans.

9. The use or method according to any one of the preceding claims, wherein the polysaccharide is β -glucan.

10. Use or method according to any one of the preceding claims, wherein the molecular weight of the polysaccharide is in the range of 1000000-.

11. The use or method of any preceding claim, wherein the polysaccharide has a filtration ratio of no higher than 1.5.

12. The use or method of any preceding claim wherein the polysaccharide is provided to the oil-bearing formation in the form of a treatment fluid having a concentration of between 20ppm and 10000 ppm.

13. The use or method of any preceding claim wherein the polysaccharide is provided to the oil-bearing formation in the form of a treatment fluid, the treatment fluid being an aqueous fluid.

14. The use or method of claim 13, wherein the aqueous fluid additionally comprises an organic solvent.

15. The use or method of any preceding claim, wherein the polysaccharide is provided to the oil-bearing formation in the form of a treatment fluid having a viscosity at a temperature of 25 ℃ and at a constant temperature for 10s according to rotational rheology^-1Is at least 10%, at least 25%, or even at least 50% higher than the viscosity of a fluid of the same composition as the treatment fluid but without the polysaccharide.

16. The use or method of any preceding claim, wherein the polysaccharide is provided to the oil-bearing formation in the form of a treatment fluid having a viscosity in the range of 50cP to 2000cP, such as in the range of 100cP to 1000cP, or in the range of 200cP to 600 cP.

17. The use or method of any preceding claim, wherein the polysaccharide is provided to an aqueous phase in the oil-bearing formation, the aqueous phase having a pH in the range of at least 8 or at least 8.5, such as 8-10.5, or 8-10, or 8-9.5, or 8-9, or 8.5-10.5, or 8.5-10, or 8.5-9.5.

18. Use or method according to any of the preceding claims, wherein the polysaccharide is provided to an oil-bearing formation having a temperature of at least 120 ℃, such as in the range of 120 ℃, -160 ℃, or in the range of 120 ℃, -150 ℃.

19. Use or method according to any one of the preceding claims, wherein the polysaccharide is provided to an aqueous phase of the oil-bearing formation, the aqueous phase having a Total Dissolved Solids (TDS) of more than 40000ppm, such as more than 150000 ppm.

20. The use or method of any preceding claim, wherein the polysaccharide is provided to the oil-bearing formation in the presence of a biocide.

21. Use or method according to any of the preceding claims, wherein the polysaccharide is provided into an aqueous phase of the oil-bearing formation such that the viscosity of the aqueous phase is 0.1-1 seconds at the temperature of the oil-bearing formation^-1In the range of 50% to 100% of the viscosity of the particular oil phase at low shear rates.

22. The use or method of any preceding claim, wherein the use or method is for performing an enhanced oil recovery operation.

23. The use or method of any of claims 1-22, wherein the sugar is provided to the oil-bearing formation in the form of a drilling fluid (e.g., wherein the method comprises drilling a well in the oil-bearing formation during or after providing the sugar to the oil-bearing formation).

24. The use or method of any of claims 1-22, wherein the sugar is provided to the oil-bearing formation in the form of a fracturing fluid (e.g., wherein the method comprises fracturing in the oil-bearing formation during or after providing the sugar to the oil-bearing formation).