Method for reducing the viscosity of viscosified fluids for applications in natural gas and oil fields

Abstract

A method to reduce the viscosity of viscosified treatment fluids is disclosed herein. The method includes a water soluble polymer, a breaker system containing at least one aliphatic azo-compound, mixing the viscosified treatment fluid and the breaker composition and allowing the viscosified treatment fluid and the breaker composition to interact whereby the viscosity of the viscosified treatment is reduced. The application of the process in the production of oil and gas and to the treatment fluids is also discussed.

Claims

1. A method of reducing the viscosity of a viscosified treatment fluid in natural gas and/or oilfield stimulation processes comprising the steps of: (i) providing a viscosified treatment fluid containing a water soluble polymeric gelling agent wherein the viscosified treatment fluid is prepared using natural occurring brines selected from the group consisting of formation water, produced water and/or flow back from a well after a stimulation process, and mixtures thereof, wherein the natural occurring brine has a total organic carbon (TOC) in the range of 310-5000 mg/I and a total dissolved solids (TDS) salt of at least 10,000 ppm, the water soluble polymeric gelling agent including at least structural units of formula (I) ##STR00008## wherein R1, R2 and R3 independently are hydrogen or C.sub.1-C.sub.6-alkyl, up to 95% by weight of the water soluble polymeric gelling agent of structural units of formula (II) ##STR00009## wherein R4 is hydrogen or C.sub.1-C.sub.6-alkyl, R5 is hydrogen, a cation of an alkaline metal, of an earth alkaline metal, of ammonia and/or of an organic amine, A is a covalent CS bond or a two-valent organic bridging group, and up to 20% by weight of the water soluble polymeric gelling agent of structural units of formula (V) ##STR00010## wherein R17 is hydrogen or, C.sub.1-C.sub.6-alkyl, and R18 and R19 are independently of one another hydrogen, a cation of an alkaline metal, of an earth alkaline metal, of ammonia and/or of an organic amine, B is a covalent CP bond or a two-valent organic bridging group, (ii) providing a breaker composition containing an aliphatic azo-compound selected from the group consisting of: 2,2-Azobis[2-(2-imidazolin-2-yl)propane], 2,2-Azobis[2-(2-imidazolin-2-yl)propane]dihydrochloride, 2,2-Azobis[2-(2-imidazolin-2-yl)propane]disulfate dihydrate, 2,2-Azobis{2-[1-(2-hydroxyethyl)-2-imidazolin-2-yl]propane}dihydrochloride, 2,2-Azobis(2-methyl propionamidine) dihydrochloride, 2,2-Azobis[N-(2-carboxyethyl)-2-methylpropionamidine]hydrate, 2,2-Azobis(1-imino-1-pyrrolidino-2-ethylpropane)dihydrochloride, 2,2-Azobis[2-methyl-N-(2-hydroxyethyl)propionamide], 2,2-Azobis{2-methyl-N-[1,1-bis(hydroxymethyl)-2-hydroxyethl]propionamide}, 2,2-Azobis(2.4-dimethyl valeronitrile), 2,2-Azobis(4-methoxy-2.4-dimethyl valeronitrile), Dimethyl 2,2-azobis(2-methylpropionate), 1,1-Azobis(cyclohexane-1-carbonitrile), 2,2-Azobis[N-(2-propenyl)-2-methylpropionamide], 1-[(1-cyano-1-methylethyl)azo]formamide 2,2-Azobis(N-butyl-2-methylpropionamide), 2,2-Azobis(N-cyclohexyl-2-methylpropionamide), and mixtures thereof, (iii) mixing said viscosified treatment fluid and said breaker composition and injecting the mixture of viscosified treatment fluid and breaker composition into a natural gas or oil reservoir, (iv) allowing said viscosified treatment fluid and said breaker composition to interact whereby the viscosity of the viscosified treatment fluid is reduced.

2. The method of claim 1 wherein a concentration of the aliphatic azo compound ranges from 0.01 to 10% by weight, of the total mass of the aqueous polymer solution.

3. The method of claim 1 wherein the viscosified treatment fluid is injected at a temperature below 90 C.

4. The method of claim 1 wherein the viscosified treatment fluid is injected as hydraulic fracturing fluid.

5. A method of stimulating a natural gas and/or oil reservoir comprising the steps of: (i) providing a viscosified treatment fluid containing a water soluble polymeric gelling agent wherein the viscosified treatment fluid is prepared using natural occurring brines selected from the group consisting of formation water, produced water and/or flow back from a well after a stimulation process, and mixtures thereof, wherein the natural occurring brine has a total organic carbon (TOC) in the range of 310-5000 mg/I and a total dissolved solids (TDS) salt of at least 10,000 ppm, the water soluble polymeric gelling agent including at least structural units of formula (I) ##STR00011## wherein R1, R2 and R3 independently are hydrogen or C.sub.1-C.sub.6-alkyl, up to 95% by weight of the water soluble polymeric gelling agent of structural units of formula (II) ##STR00012## wherein R4 is hydrogen or C.sub.1-C.sub.6-alkyl, R5 is hydrogen, a cation of an alkaline metal, of an earth alkaline metal, of ammonia and/or of an organic amine, A is a covalent CS bond or a two-valent organic bridging group, and up to 20% by weight of the water soluble polymeric gelling agent of structural units of formula (V) ##STR00013## wherein R17 is hydrogen or, C.sub.1-C.sub.6-alkyl, and R18 and R19 are independently of one another hydrogen, a cation of an alkaline metal, of an earth alkaline metal, of ammonia and/or of an organic amine, B is a covalent CP bond or a two-valent organic bridging group, (ii) providing a breaker composition containing an aliphatic azo-compound selected from the group consisting of: 2,2-Azobis[2-(2-imidazolin-2-yl)propane], 2,2-Azobis[2-(2-imidazolin-2-yl)propane]dihydrochloride, 2,2-Azobis[2-(2-imidazolin-2-yl)propane]disulfate dihydrate, 2,2-Azobis{2-[1-(2-hydroxyethyl)-2-imidazolin-2-yl]propane}dihydrochloride, 2,2-Azobis(2-methyl propionamidine) dihydrochloride, 2,2-Azobis[N-(2-carboxyethyl)-2-methylpropionamidine]hydrate, 2,2-Azobis(1-imino-1-pyrrolidino-2-ethylpropane)dihydrochloride, 2,2-Azobis[2-methyl-N-(2-hydroxyethyl)propionamide], 2,2-Azobis{2-methyl-N-[1,1-bis(hydroxymethyl)-2-hydroxyethl]propionamide}, 2,2-Azobis(2.4-dimethyl valeronitrile), 2,2-Azobis(4-methoxy-2.4-dimethyl valeronitrile), Dimethyl 2,2-azobis(2-methylpropionate), 1,1-Azobis(cyclohexane-1-carbonitrile), 2,2-Azobis[N-(2-propenyl)-2-methylpropionamide], 1-[(1-cyano-1-methylethyl)azo]formamide 2,2-Azobis(N-butyl-2-methylpropionamide), 2,2-Azobis(N-cyclohexyl-2-methylpropionamide), and mixtures thereof, (iii) mixing said viscosified treatment fluid and said breaker composition and injecting the mixture of viscosified treatment fluid and breaker composition into a natural gas or oil reservoir, (iv) allowing said viscosified treatment fluid and said breaker composition to interact whereby the viscosity of the viscosified treatment fluid is reduced, (v) removing the viscosity reduced fluid from step (iv) from the natural gas or oil reservoir.

6. A method for the production of oil and/or natural gas which includes the stimulation of the natural gas and/or oil reservoir by the steps of: (i) providing a viscosified treatment fluid containing a water soluble polymeric gelling agent wherein the viscosified treatment fluid is prepared using natural occurring brines selected from the group consisting of formation water, produced water and/or flow back from a well after a stimulation process, and mixtures thereof, wherein the natural occurring brine has a total organic carbon (TOC) in the range of 310-5000 mg/I and a total dissolved solids (TDS) salt of at least 10,000 ppm, the water soluble polymeric gelling agent including at least structural units of formula (I) ##STR00014## wherein R1, R2 and R3 independently are hydrogen or C.sub.1-C.sub.6-alkyl, up to 95% by weight of the water soluble polymeric gelling agent of structural units of formula (II) ##STR00015## wherein R4 is hydrogen or C.sub.1-C.sub.6-alkyl, R5 is hydrogen, a cation of an alkaline metal, of an earth alkaline metal, of ammonia and/or of an organic amine, A is a covalent CS bond or a two-valent organic bridging group, and up to 20% by weight of the water soluble polymeric gelling agent of structural units of formula (V) ##STR00016## wherein R17 is hydrogen or, C.sub.1-C.sub.6-alkyl, and R18 and R19 are independently of one another hydrogen, a cation of an alkaline metal, of an earth alkaline metal, of ammonia and/or of an organic amine, B is a covalent CP bond or a two-valent organic bridging group, (ii) providing a breaker composition containing an aliphatic azo-compound selected from the group consisting of: 2,2-Azobis[2-(2-imidazolin-2-yl)propane], 2,2-Azobis[2-(2-imidazolin-2-yl)propane]dihydrochloride, 2,2-Azobis[2-(2-imidazolin-2-yl)propane]disulfate dihydrate, 2,2-Azobis{2-[1-(2-hydroxyethyl)-2-imidazolin-2-yl]propane}dihydrochloride, 2,2-Azobis(2-methyl propionamidine) dihydrochloride, 2,2-Azobis[N-(2-carboxyethyl)-2-methylpropionamidine]hydrate, 2,2-Azobis(1-imino-1-pyrrolidino-2-ethylpropane)dihydrochloride, 2,2-Azobis[2-methyl-N-(2-hydroxyethyl)propionamide], 2,2-Azobis{2-methyl-N-[1,1-bis(hydroxymethyl)-2-hydroxyethl]propionamide}, 2,2-Azobis(2.4-dimethyl valeronitrile), 2,2-Azobis(4-methoxy-2.4-dimethyl valeronitrile), Dimethyl 2,2-azobis(2-methylpropionate), 1,1-Azobis(cyclohexane-1-carbonitrile), 2,2-Azobis[N-(2-propenyl)-2-methylpropionamide], 1-[(1-cyano-1-methylethyl)azo]formamide 2,2-Azobis(N-butyl-2-methylpropionamide), 2,2-Azobis(N-cyclohexyl-2-methylpropionamide), and mixtures thereof, (iii) mixing said viscosified treatment fluid and said breaker composition and injecting the mixture of viscosified treatment fluid and breaker composition into a natural gas or oil reservoir, (iv) allowing said viscosified treatment fluid and said breaker composition to interact whereby the viscosity of the viscosified treatment fluid is reduced, (v) removing the viscosity reduced fluid from step (iv) from the natural gas or oil reservoir.

Description

EXAMPLES

Example 1: Preparation of a Polymer Via Inverse Emulsion Polymerization

(1) 37 g sorbitan monooleate were dissolved in 160 g C.sub.11-C.sub.16 isoparaffin. 100 g water in a beaker were cooled to 5 C., then 50 g 2-acrylamido-2-methylpropane sulfonic acid and 10 g vinylphosphonic acid were added. The pH was adjusted to 7.1 with aqueous ammonia solution. Subsequently 223 g acryl amide solution (60 weight % in water) were added.

(2) Under vigorous stirring the aqueous monomer solution was added to the isoparaffin mixture. The emulsion was then purged for 45 min with nitrogen.

(3) The polymerization was started by addition of 0.5 g azoisobutyronitrile in 12 g isoparaffin and heated to 50 C. To complete the reaction the temperature was increased to 80 C. and maintained at this temperature for 2 hours. The polymer emulsion was cooled to room temperature. As product, a viscous fluid was obtained.

Example 2: Preparation of a Polymer Via Gel Polymerization

(4) 400 ml deionized water and 9.2 ml 25 weight-% aqueous ammonia solution were placed in a reaction vessel. 70 g acryl amide and 30 g acrylic acid were added under stirring. The solution was purged with nitrogen and heated to 50 C. The polymerization was started by addition of 5 ml of a 20% by weight aqueous solution of ammonium persulfate. To complete the reaction the temperature was increased to 80 C. and maintained at this temperature for 2 hours. After cooling to room temperature a highly viscous gel was obtained.

Example 3

(5) 800 ml of tab water and 8 g of a non-ionic surfactant with a HLB of about 13 were mixed in a Waring blender. 14 g of the polymer emulsion of example 1 were added and mixed for 4 min. The viscosity of the linear gel prior to breaking was determined using the Brookfield rheometer at 100 s.sup.1 and 30 C. The starting viscosity was 142 mPas.

(6) To 200 g of the so prepared polymer solution the breaker was added, the quantities given in table 1. The sample was put into a sealed glass flask and heated to 82 C. without stirring for 4 h. Then the bottles were allowed to cool to room temperature and the viscosity of the broken fluid was determined using the same conditions as described above. The results are given in table 1.

(7) TABLE-US-00001 TABLE 1 Quantity, Viscosity, Example breaker [gram] [mPas] 3a, comparative 2,5-dimethyl-2,5-di(2- 0.15 68 ethylhexanoyl peroxy) hexane 3b, comparative sodium persulfate 0.15 <5 3c 2,2-azobis(isobutyronitrile) 0.15 86 3d 2,2-azobis(isobutyronitrile) 0.30 82

(8) It is obvious that sodium persulfate is the most active breaker in a polymer solution using water free from salt and organic impurities coming from oil or gas.

(9) It is further obvious that an aliphatic azo compound added to the polymer solution leads to a degradation of the polymers and therefore to reduced viscosities of the polymer solution. The results are similar to breaker like peroxides that are described in the literature.

Example 4

(10) Original formation water containing about 4.2% sodium, 0.1% potassium, 0.1% strontium, 0.5% calcium, 0.1% magnesium, 7.2% chloride, 0.1% bromide, 0.1% sulphate, others 0.2%, the total dissolved solids (TDS) being 12.5%, % given as weight percent referred to quantity of the formation water, is used in this example The total organic carbon content (TOC) is 310 mg/l.

(11) 800 ml of this formation water and 8 g of a non-ionic surfactant with a HLB of about 13 were mixed in a Waring blender. 22 g of the polymer emulsion of example 1 were added and mixed for 10 min. The viscosity of the linear gel prior to breaking was determined using the Brookfield rheometer at 100 s.sup.1 and 30 C. The starting viscosity was 76 mPas.

(12) To 200 g of the so prepared polymer solution the breaker was added, the quantities given in table 2. The sample was put into a sealed glass flask and heated to 82 C. without stirring for 2 h. Then the bottles were allowed to cool to room temperature and the viscosity of the broken fluid was determined using the same conditions as described above. The results are given in table 2.

(13) TABLE-US-00002 TABLE 2 Quantity, Viscosity, Example breaker [gram] [mPas] 4a, comparative sodium persulfate 0.4 >76 4b 2,2-azobis(isobutyronitrile) 0.4 65 4c 1,1Azobis-(cyclohexane-1- 0.6 64 carbonitrile) 4d 2,2-azobis(2-methylpropion 0.6 65 amidine)*2 HCl

(14) The results clearly show that the most common oxidative breaker sodium persulfate completely fails to degrade the polymer and to reduce the viscosity of the polymer solution in an original formation water containing organic residues.

Example 5

(15) 4.1 g of the polymer gel of example 2 were diluted with 200 ml tab water and thoroughly mixed. The viscosity of the polymer solution was 89 mPas, determined using the Brookfield rheometer at 25 C. and 100 s.sup.1.

(16) Then breaker or breaker system was added, the quantities given in table 3.

(17) The polymer solution was placed in bottles, sealed and put into a water bath at 82 C. without stirring. After 1.5 h the bottles were allowed to cool to room temperature and the viscosity of the broken fluid was determined using the same conditions as for the starting polymer solution.

(18) TABLE-US-00003 TABLE 3 Viscosity, Example Breaker Quantity, g mPas 5a 2,2-azobis(isobutyronitrile) 0.6 64 5b 2,2-azobis(2-methylpropion 0.4 58 amidine)*2 HCl 5c 1,1Azobis-(cyclohexane-1- 0.6 59 carbonitrile)

Example 6

(19) 1 l original formation water from example 4 was treated with 10 g charcoal for 1 h and then filtered. The TOC was reduced by this treatment from 310 mg/l to 18 mg/l.

(20) 800 ml of this formation water and 8 g of a non-ionic surfactant with a HLB of about 13 were mixed in a Waring blender. 22 g of the polymer emulsion of example 1 were added and mixed for 10 min. The viscosity of the linear gel prior to breaking was determined using the Fann 35 rheometer at 100 rpm at room temperature. The starting viscosity was 71 mPas, the pH before adding the breaker was 7.

(21) To 200 g of the so prepared polymer solution the breaker was added, the quantities given in table 4. The sample was put into a sealed glass flask and heated to 82 C. without stirring for 2 h. Then the bottles were allowed to cool to room temperature and the viscosity of the broken fluid was determined using the same conditions as described above. The results are given in table 4.

(22) TABLE-US-00004 TABLE 4 Quantity Viscosity Example Breaker [gram] [mPas] pH 6a sodium persulfate 0.4 59 2 comparative 6b 2,2-azobis(isobutyronitrile) 0.4 64 7 6c 1,1Azobis-(cyclohexane-1- 0.6 57 7 carbonitrile) 6d 2,2-azobis(2-methylpropion 0.6 60 7 amidine)*2 HCl

(23) The results clearly show that persulfate breaker is strongly affected by TOC generated by dissolved or finely dispersed organic residues from oil and gas as typically present in produced water or flow back. In contrast the azo breaker are essentially unaffected by organic residues and gives reproducible results independent from TOC content.

(24) In addition, the results show that the azo breaker does not influence the pH of the treatment fluid during breaking as sodium persulfate does.

Example 7

(25) 200 ml original formation water from example 4 were filled into a blender. 2 g of a non-ionic surfactant with a HLB of about 13 were added and mixed in a Waring blender. 3.5 g of the polymer emulsion of example 1 were added and mixed for 10 min. The pH is adjusted to 4-5 using 10% acetic acid. Then 0.5 g 2,2-azobis(isobutyronitrile) and 0.2 g Zr triethanolamine complex are added under stirring. After about 60 s a viscous gel is formed that could be lifted easily from the beaker using a glass rod. The viscosity determined by a Brookfield rheometer was >1200 mPas.

(26) The crosslinked gel was placed in a flask equipped with a stirrer and heated to 82 C. for 3.5 h. The polymer gel degraded to give a viscous liquid.

(27) The viscosity was 290 mPas at 100 s.sup.1 at 30 C. in the Brookfield rheometer.

(28) A very strong crosslinked polymer gel can be degraded to obtain a broken fluid with low viscosity.