CN110630217B - Chlorine dioxide oil-water well production and injection increasing process for tight oil reservoir - Google Patents
Chlorine dioxide oil-water well production and injection increasing process for tight oil reservoir Download PDFInfo
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- CN110630217B CN110630217B CN201910865169.6A CN201910865169A CN110630217B CN 110630217 B CN110630217 B CN 110630217B CN 201910865169 A CN201910865169 A CN 201910865169A CN 110630217 B CN110630217 B CN 110630217B
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/524—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning organic depositions, e.g. paraffins or asphaltenes
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/54—Compositions for in situ inhibition of corrosion in boreholes or wells
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B37/00—Methods or apparatus for cleaning boreholes or wells
- E21B37/06—Methods or apparatus for cleaning boreholes or wells using chemical means for preventing, limiting or eliminating the deposition of paraffins or like substances
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/02—Equipment or details not covered by groups E21B15/00 - E21B40/00 in situ inhibition of corrosion in boreholes or wells
Abstract
A chlorine dioxide oil-water well production and injection increasing process for a tight oil reservoir mainly comprises the following steps: 1) removing wax precipitation, scaling and corrosive substances on the inner surface and the outer surface of a shaft oil sleeve by using pretreatment liquid; 2) neutralizing and softening excessive divalent metal cation Ca of stratum by using front pad liquid2+、Mg2+(ii) a 3) Removing the blockage of the stratum by using the main treatment fluid; 4) keeping the postposition liquid near the perforation blasthole and cleaning the perforation blasthole; 5) ejecting the pretreatment liquid, the front pad liquid, the main treatment liquid and the post-treatment liquid into the stratum by using a displacement liquid, and retaining the displacement liquid in the oil casing; the invention oxidizes H generated by the reaction of ferrous sulfide and acid2S to reduce H2S can corrode the oil casing, can oxidize organic matter residues of organisms, vegetable gum fracturing fluid residues, micelle agent and mutual solvent in the treatment fluid to dissolve heavy hydrocarbon remained in rock pores, and can be used as a bonding agent for reaction residues, so that secondary pollution is effectively prevented, and the effect of acidification and blockage removal is improved.
Description
Technical Field
The invention relates to the field of oil and gas field development, in particular to a process for increasing the yield and the injection of a compact oil reservoir chlorine dioxide oil-water well.
Background
In oil field exploitation, the exploitation effect is seriously affected by stratum and equipment blockage caused by iron sulfide, bacterial communities, high polymers, dirt and the like.
The conventional acid can dissolve calcium carbonate scale, ferrous sulfide and the like existing in the stratum, but the dissolved ferrous sulfide can be re-precipitated to block the pore space of an oil layer along with the continuous rising of the pH value of residual acid in the stratum along with the prolonging of the reaction time.
Chlorine dioxide is an explosive gas with a boiling point of 10 ℃ at normal temperature and pressure, is a red-yellow gas, turns into red liquid at-11 ℃ and forms crystals at-59 ℃, and the solubility of chlorine dioxide in water is 2.8g/L (22 ℃). Under the condition that the ambient temperature is less than 30 ℃ and no organic matters or other impurities exist, the lowest mass fraction of chlorine dioxide gas is 10 percent, and when the content of chlorine dioxide gas in the air is higher than 10 percent, the chlorine dioxide gas has extremely high explosiveness. Chlorine dioxide is extremely unstable and rapidly decomposes in the presence of water to form a variety of strong oxidants, such as HClO3、HClO2、HClO、Cl2、O3、H2O2These oxides, when combined together, generate a plurality of active groups (i.e., radicals) having extremely strong oxidizing ability, which can excite inactive hydrogen on the organic ring to generate R.radical (RH represents an organic substance) through dehydrogenation reaction, and which can serve as a inducer for further oxidation, and the radicals can also react with hydroxyl groups to form-SO on the aromatic hydrocarbon ring3H、-NO2And the like, so that an unstable hydroxyl substituted intermediate is generated, ring opening cracking is easy to occur until the intermediate is completely decomposed into inorganic matters. It can also convert reducing substances such as S2-、SO3 2-、SbO3 2-、NO2 -、NO3 -、CN-Etc. to reduce the emission concentration. It is known that chlorine dioxide has an oxidation capacity 9 times greater than that of hypochlorous acid, and that the oxidation product is free of AOX species. Chlorine dioxide theoretically has an oxidizing power 2.6 times that of chlorine gas in terms of available chlorine, and in application, the oxidizing power of chlorine dioxide is not completely used, and most of the reaction in water is only that chlorine dioxide is reduced into chlorite.
The influence of the pH value on the oxidation capacity of the chlorine dioxide is very obvious, and the stronger the acidity, the stronger the oxidation capacity of the chlorine dioxide is, so that in practical application, the oxidized substances are in certain acidic conditions according to various environments, and the oxidation effect of the chlorine dioxide is favorably exerted.
Disclosure of Invention
To solve the problems mentioned aboveThe invention aims to provide a production and injection increasing process for a compact oil reservoir chlorine dioxide oil-water well, which comprises the steps of adding chlorine dioxide into an acidification production increasing solution, oxidizing oleophilic ferrous sulfide into hydrophilic ferric oxide hydrate, chelating the hydrophilic ferric oxide hydrate by an additive in acid, and oxidizing H generated by the reaction of ferrous sulfide and acid by chlorine dioxide2S to reduce H2S can corrode the oil casing, and can also oxidize biological organic matter residues and vegetable gum fracturing fluid residues, and micelle agent and mutual solvent in the treatment fluid can dissolve heavy hydrocarbon remained in rock pores, and the heavy hydrocarbon can be used as a bonding agent for reaction residues, so that secondary pollution is effectively prevented, and the acidification blockage removal effect is improved.
The technical scheme for realizing the purpose of the invention is as follows:
a chlorine dioxide oil-water well production and injection increasing process for a tight oil reservoir comprises the following steps:
1) removing wax precipitation, scaling and corrosive substances on the inner surface and the outer surface of a shaft oil sleeve by using pretreatment liquid;
2) neutralizing and softening excessive divalent metal cation Ca of stratum by using front pad liquid2+、Mg2+；
3) Removing the blockage of the stratum by using the main treatment fluid;
4) keeping the postposition liquid near the perforation blasthole and cleaning the perforation blasthole;
5) and (4) ejecting the pretreatment liquid, the front pad liquid, the main treatment liquid and the post-treatment liquid into the stratum by using a displacement liquid, wherein the displacement liquid is remained in the oil casing.
Further, in the step 1), the pretreatment solution is composed of the following materials in parts by weight:
20-50 parts of dilute acid liquid, 5-10 parts of paraffin remover, 1-5 parts of osmotic wetting agent, 1-4 parts of surfactant and 6-10 parts of demulsifier;
the dilute acid solution consists of the following materials in parts by weight:
3-7 parts of hydrochloric acid and 2-5 parts of hydrofluoric acid;
the mass concentration of the hydrochloric acid is 5-8%, and the mass concentration of the hydrofluoric acid is 2-3%;
the paraffin remover is one of carbon tetrachloride, benzene, toluene and solvent oil;
the osmotic wetting agent is a wetting agent SX-YTRSJL (available from Shanghai Shengxuan Biochemical industry Co., Ltd.);
the surfactant is SX-YTQYEA (sold by Shanghai Shengxuan biochemical engineering Co., Ltd.);
the demulsifier is demulsifier MQ801 (available from Guangzhou vast Qing environmental protection science and technology Co., Ltd.).
Further, in the step 2), the front pad liquid consists of the following materials in parts by weight: 70-80 parts of potassium chloride solution, 5-10 parts of EDTA and 6-10 parts of scale inhibitor;
the mass concentration of the potassium chloride solution is 2-7%;
the scale inhibitor is a CH-003 scale inhibition dispersant (sold by Gallery Chenghua chemical Co., Ltd.).
Further, in the step 3), the dosage of the main treatment fluid is 1.5-5 times of the volume of the dynamic fracture of the reservoir, and the main treatment fluid consists of the following materials in parts by weight:
40-50 parts of chlorine dioxide solution, 30-40 parts of hydrochloric acid, 6-10 parts of active agent, 3-7 parts of corrosion inhibitor, 6-8 parts of iron ion stabilizer, 6-10 parts of mutual solvent and 10-15 parts of cleanup additive;
the concentration of the chlorine dioxide solution is 3000 ppm;
the mass concentration of the hydrochloric acid is 6-8%;
the active agent is fatty alcohol polyoxyethylene ether sodium sulfate or lauryl sodium sulfate;
the corrosion inhibitor is one of diethylenetriamine penta (methylene phosphonic acid), hydroxyethylidene diphosphonic acid, sodium nitrate, potassium fluoride and sodium tripolyphosphate;
the iron ion stabilizer is an iron ion stabilizer for HT215 acidification, ascorbic acid, citric acid or tartaric acid;
the mutual solvent is diethylene glycol monoethyl ether;
the cleanup additive is one of long-chain fatty alcohol polyoxyethylene ether, alkylphenol polyoxyethylene ether, fatty acid polyoxyethylene ester, polyoxyethylene alkylamine and polyoxyethylene alkylamide.
Further, in the step 4), the post liquid is composed of the following materials in parts by weight:
80-90 parts of potassium chloride solution and 8-15 parts of cleanup additive;
the mass concentration of the potassium chloride solution is 2-3%;
the cleanup additive is one of polyoxyethylene fatty acid ester, polyoxyethylene alkylamine or polyoxyethylene alkylamide.
Further, in the step 5), for the water well, the displacement liquid is active water; for oil wells, the displacement fluid is crude oil or diesel oil, and the amount of the displacement fluid is 0.5m added to the volume of the ground pipeline and the well bore3。
The invention has the advantages that:
1) the invention relates to a compact oil reservoir chlorine dioxide oil-water well production and injection increasing process, which oxidizes oleophylic ferrous sulfide into hydrophilic iron oxide hydrate, and chlorine dioxide is chelated by an additive in acid; chlorine dioxide also oxidizes H produced by the reaction of ferrous sulfide and acid2S to reduce H2S can corrode the oil casing, can oxidize biological organic matter residues and vegetable gum fracturing fluid residues, and micelle agent and mutual solvent in the treatment fluid can dissolve heavy hydrocarbon remained in rock pores, and can be used as a bonding agent for reaction residues, so that secondary pollution is effectively prevented, and the acidification blockage removal effect is improved;
2) the process for increasing the yield and the injection of the chlorine dioxide oil-water well of the tight oil reservoir has the advantages of simple process and easy operation;
3) the production and injection increasing process for the chlorine dioxide oil-water well of the tight oil reservoir reduces the consumption of chlorine dioxide and saves the cost.
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present invention more apparent, the embodiments of the present invention will be described in detail and completely with reference to the accompanying drawings, and it is to be understood that the described embodiments are a part of the embodiments of the present invention, but not all of the embodiments of the present invention. All other embodiments, which can be obtained by a person skilled in the art without any inventive step based on the embodiments of the present invention, are within the scope of the present invention. Thus, the following detailed description of the embodiments of the present invention, presented in the figures, is not intended to limit the scope of the invention, as claimed, but is merely representative of selected embodiments of the invention. All other embodiments, which can be obtained by a person skilled in the art without any inventive step based on the embodiments of the present invention, are within the scope of the present invention.
Experimental research on yield and injection increasing principle of chlorine dioxide oil-water well
a. Overview
In oil field exploitation, the exploitation effect is seriously affected by stratum and equipment blockage caused by iron sulfide, bacterial communities, high polymers, dirt and the like. Theoretical analysis and experimental results prove that chlorine dioxide can eliminate various blockages by means of strong oxidizing capacity and sterilizing capacity of the chlorine dioxide, the production and injection increasing of an oil-water well is realized, and in addition, for an oil field which adopts high polymer or microorganism for production increasing and oil displacement, a reservoir stratum is treated by the chlorine dioxide, the blockage of seepage channels caused by the trapping and retention of the substances in the stratum can be eliminated, and the exploitation life of an old well can be further prolonged.
b. Relieving blockage of fracturing fluid
Viscosity influence: the test results are shown in Table 1
TABLE 1 influence of chlorine dioxide on guar gum viscosity
The results show that: the non-activated chlorine dioxide and the activated chlorine dioxide have stronger sterilization and corrosion prevention effects; the activated chlorine dioxide is thorough in gel breaking, the viscosity after gel breaking is low, vegetable gum residues can be hydrated, and the gel breaker cannot; under the same conditions, the viscosity of the jelly is reduced when the temperature is increased.
The effect of precipitation of guar gum solution and the test results are shown in Table 2
The results show that: the precipitates of the group 1 and the group 2 are more and have no great difference, which indicates that the gel breaker has no influence on the residue precipitates after the gel breaker and the guanidine gum solution act; the precipitates of the 3 rd group and the 4 th group are less and have no great difference, which shows that the precipitates of the chlorine dioxide and the guar gum liquid have the effect of reducing after the chlorine dioxide and the guar gum liquid act. It also shows that within a certain range, the concentration is not in inverse proportion to the precipitate.
TABLE 2 influence of chlorine dioxide on guar solution precipitates
c. The results of the PO series colloidal solvent test are shown in Table 3
TABLE 3 dissolution behavior of gum solvent for crude oil asphaltenes
Through comprehensive evaluation, the colloid solvent of the formulas of PO 4, PO 5, PO 6 and PO 7 has good heat resistance, acid resistance and compatibility and good performance of dissolving crude oil asphaltene, and can be applied to oilfield acidizing fluid together with chlorine dioxide.
d. Eliminating efficiency of inorganic scale
The mixed acid formed by the chlorine dioxide and the initiator has stronger scale dissolving capacity, particularly has stronger dissolving capacity on calcium carbonate scale widely existing in oil fields, and the test data are shown in table 4.
TABLE 4 amount (g) of dissolved chlorine dioxide system for various scales
Note: 50ml each of 20 ℃ chlorine dioxide system and 15% hydrochloric acid.
From the experimental data, it can be seen that ClO2The system compounded with the activating agent has stronger scale dissolving capacity than that of the conventional hydrochloric acid, the scale dissolving speed is slightly slower than that of the conventional hydrochloric acid, and a certain retarding effect is achieved; whether hydrochloric acid or ClO2Para CaCO3The dissolving capacity of the scale is obviously better than that of sulfate scale, and other scale removing components are required to be added when the sulfate scale is encountered on site.
e. The results of the killing and degradation of the bacterial flora are shown in Table 5
TABLE 5 killing and degradation of bacterial communities by chlorine dioxide
Note: "+" indicates growth; "-" indicates no growth; and (5) bacteria ck: no sterilization treatment is carried out; CK0 was not inoculated.
As can be seen from the table, the sulfate-reducing bacteria treated with chlorine dioxide at lower concentration (10, 15mg/L) and shorter time (5-10min) can still generate chlorine dioxide; can completely kill the sulfate reducing bacteria under the action of 50ppm concentration and long time (30 min). The sulfate reducing bacteria can be treated by the system at low concentration (50mg/L) for a long time (30min) or at high concentration (100mg/L) for a short time (less than 5 min) on site so as to achieve the purpose of inactivation.
f. The iron corrosives were removed with the results shown in Table 6
TABLE 6 removal efficiency of chlorine dioxide on ferrous corrosives
As can be seen from the table, the first group of HCl + PO series solvents formed an average residue of 0.1888g after acting on FeS; the second group of HCl + chlorine dioxide solutions reacted on FeS to form an average of 0.0473g of residue. The first group was on average 2.96 times more residues than the second group; the first group of reaction products isFe2+In the earth formation H2Water-insoluble FeS can be formed under the action of S gas; the second group of reaction products is Fe3+Not in contact with H in the formation2S reacts with SO3-、SO4 2-Soluble ferric sulfate salt is generated.
g. Core damage experimental analysis
The test selected the core of the 10-141 wells in the Maring oil field (see Table 7).
TABLE 7 core numbering table
Before the experiment, the core is divided into two groups according to the SY/T5358-94 standard and necessary pretreatment is carried out, wherein 502-6, 502-8 are used as the first group, and 502-5, 502-7 are used as the second group.
Conclusion: in core damage testing, hydrochloric acid and CLO were squeezed in2Respectively have a permeability (K value) of 8.6X 10-3μm2And 82.3X 10-3μm2Becomes 85.8 × 10-3μm2And 604X 10-3μm2From the data, the system does not cause damage to the rock core; in the experiment of manually simulating the blockage of the blockage to the core, the permeability (K value) of the core is respectively 145 multiplied by 10-3μm2And 114 × 10-3μm2Down to 3.8X 10-3μm2And 0, the data show that the simulation plug can meet the test requirements on the blockage of the core; in hydrochloric acid with CLO2In the test of releasing the simulated blocking core, the permeability of the core is respectively 3.8 multiplied by 10-3μm2And 0 increased to 95X 10-3μm2And 345 × 10-3μm2，ClO2The system has obvious blockage removal effect; in hydrochloric acid blockage removal test, the residual resistance coefficient of the rock core is changed from 38.6 to 1.52, and the blockage removal rate is 65%; ClO2In a system blockage removal test, the residual resistance coefficient of the rock core is changed from 114 to 0.33, and the blockage removal rate is 303%.
h. Corrosiveness of
Purpose of the test: a weight loss method is adopted, a No. 20 carbon steel standard test piece is immersed in test solutions of chlorine dioxide solution, chlorine dioxide solution + corrosion inhibitor, HCl solution and HCl + corrosion inhibitor, and after a certain period of time, the corrosion speed of each test solution to the test piece is calculated according to the weight loss of the test piece.
The test conditions required: the chlorine dioxide blockage removal is a strong oxidant, is activated under the condition of an acid medium, and has strong oxidation corrosion to metal materials. In order to prevent or slow down the oxidation corrosion of the metal material, a substance for slowing down the oxidation corrosion is added into the chlorine dioxide solution, so that the oxidation corrosion speed is reduced; at the same time, the added chemical substances should be kept from reducing the activity of the chlorine dioxide and causing no other chemical reaction.
The test conditions are as follows: normal temperature and pressure, 12 hours of corrosion time and 3000ppm of chlorine dioxide solution.
Testing apparatus
Glass rod, dryer, beaker, polypropylene fiber wire, plastic tweezers, metallographic abrasive paper and 20# steel standard test piece (28.00 cm)2) An analytical balance, an acidimeter, a constant temperature water bath and a thermometer.
Test drugs: inorganic chemical reagent, organic chemical reagent, chlorine dioxide.
Test methods and procedures
Preparing the standard test piece, polishing the standard test piece from coarse to fine by using abrasive paper with different fineness until the required smooth finish is achieved, degreasing and removing dirt, fully rinsing by using water, putting the standard test piece into absolute ethyl alcohol for cleaning, taking out the standard test piece by using tweezers, drying the standard test piece by using hot air, wrapping the standard test piece by using clean filter paper, putting the standard test piece into a dryer, standing the dried standard test piece for 24 hours, and weighing the standard test piece (the precision is 0.0001 g).
Preparation of assay solution
Taking 1500ml chlorine dioxide solution (the concentration of chlorine dioxide is more than or equal to 3000mg/L), adding 3% potassium chloride, and adjusting the pH value to 2-2.5 by using citric acid (the solution is activated). Adding 4% corrosion inhibitor for preventing or slowing oxidation corrosion, stirring, and placing in three 500ml beakers as group 1 for use.
1500ml of activated chlorine dioxide solution with the same volume was prepared as above without the addition of corrosion inhibitor in three 500ml beakers, group 2, as a control.
1500ml of 15% HCl solution was prepared and used as a third group in three 500ml beakers.
1500ml of 15% HCl solution were prepared and 0.2% MH-16 was added as a fourth group in three 500ml beakers.
Corrosion test in-
And completely soaking the prepared standard test piece (weighed and numbered) in the prepared test solution, recording the time for putting the test piece into the test piece, measuring the concentration and the accurate pH value of the chlorine dioxide solution, standing for 12 hours, taking out the standard test piece, scrubbing by using an eraser by adopting a mechanical cleaning method to remove corrosion products, rinsing by using clear water, dehydrating by using absolute ethyl alcohol, drying by using hot air, wrapping by using clean filter paper, placing in a dryer for 24 hours, weighing, and calculating the corrosion speed.
The results are shown in Table 8.
TABLE 8 chlorine dioxide corrosion Performance data sheet
Calculating the corrosion speed:
u: corrosion rate, g/m2·h；
K: constant, 1 × 104 × D;
d: density of 103Kg/m3；
S: area, cm2(to the nearest 0.01);
t: time, h-hour;
w: weight loss, g (to the nearest 0.1 mg). Then:
from the above calculations, it can be seen that the corrosion rate of chlorine dioxide with corrosion inhibitor is 3.3 times lower than that of chlorine dioxide without corrosion inhibitor; ClO using urotropine as corrosion inhibitor2The corrosion speed of the system is 2.3 times higher than that of 15 percent HCl added with the corrosion inhibitor; the pickling corrosion inhibitor, the multi-effect corrosion inhibitor and the oxidizing acid corrosion inhibitor cannot play a role in reducing the oxidation corrosion speed of the chlorine dioxide. Aiming at the problem, a corrosion inhibitor capable of retarding the oxidative corrosion of chlorine dioxide is selected to be diethylenetriamine pentamethylene phosphonic acid through tests, and tests prove that the corrosion inhibitor has a certain corrosion inhibition effect on chlorine dioxide. Considering the practical condition that the contact time of chlorine dioxide with the pipeline of the equipment is short (several ten minutes) during the acidification operation, the agent is considered to basically meet the requirement of chlorine dioxide corrosion inhibition.
A chlorine dioxide oil-water well production and injection increasing process for a tight oil reservoir comprises the following steps:
1) the pretreatment liquid is used for removing wax deposition, scaling and corrosive substances on the inner surface and the outer surface of a shaft oil sleeve, breaking emulsion generated after oil and water are mixed, reducing the tension of an oil-water interface, enhancing the permeability of subsequent medicines, improving the adsorption performance, and leading an oil film attached to the surface of the dirt to be peeled off and expose the inner surface so that a contact agent can fully and effectively react with the oil film; on the other hand, the well bore can be thoroughly cleaned by pretreatment, so that the reaction loss of chemicals entering the stratum in the well bore is reduced, and the efficiency of the stratum treatment fluid is improved.
The dosage of the pretreatment liquid is 2-3 m3。
The pretreatment liquid consists of the following materials in parts by weight:
20-50 parts of dilute acid liquid, 5-10 parts of paraffin remover, 1-5 parts of osmotic wetting agent, 1-4 parts of surfactant and 6-10 parts of demulsifier,
the dilute acid solution consists of the following materials in parts by weight:
3-7 parts of hydrochloric acid and 2-5 parts of hydrofluoric acid; the concentration of the hydrochloric acid is 5-8%, and the concentration of the hydrofluoric acid is 2-3%;
the paraffin remover is one of carbon tetrachloride, benzene, toluene and solvent oil;
the osmotic wetting agent is a wetting agent SX-YTRSJL (available from Shanghai Shengxuan Biochemical industry Co., Ltd.);
the surfactant is SX-YTQYEA (sold by Shanghai Shengxuan biochemical engineering Co., Ltd.);
the demulsifier is a demulsifier MQ801 (available from Guangzhou vast Qing environmental protection science and technology Co., Ltd.).
2) Neutralizing and softening excessive divalent metal cation Ca of stratum by using front pad liquid2+、Mg2+(ii) a And the like, meanwhile, the expansion of the clay caused by wet water in the stratum is prevented, the commonly used substances are 2-7% of KCl, EDTA, a scale inhibitor, a micelle solvent and the like, and the second function is to create conditions for enabling the main treatment liquid to smoothly enter capillary pores with extremely low permeability, such as heavy hydrocarbon dissolution, tension reduction and the like.
The dosage of the front cushion liquid is 3-4 m3。
The front pad liquid consists of the following materials in parts by weight:
70-80 parts of potassium chloride solution, 5-10 parts of EDTA and 6-10 parts of scale inhibitor;
the concentration of the potassium chloride solution is 2-7%;
the scale inhibitor is a CH-003 scale inhibition dispersant (sold by Gallery Chenghua chemical Co., Ltd.).
3) Removing the blockage of the stratum by using the main treatment fluid;
the main treatment liquid consists of the following materials in parts by weight: 40-50 parts of chlorine dioxide solution, 30-40 parts of hydrochloric acid, 6-10 parts of active agent, 3-7 parts of corrosion inhibitor, 6-8 parts of iron ion stabilizer, 6-10 parts of mutual solvent and 10-15 parts of cleanup additive.
The concentration of the chlorine dioxide solution is 3000 ppm; the concentration of hydrochloric acid is 6-8%; the active agent is fatty alcohol polyoxyethylene ether sodium sulfate or lauryl sodium sulfate; the corrosion inhibitor is one of diethylenetriamine penta methylene phosphonic acid, hydroxyl ethylidene diphosphonic acid, sodium nitrate, potassium fluoride or sodium tripolyphosphate; the iron ion stabilizer is one of HT215 acidification iron ion stabilizer (available from Shandong Peiteng Petroleum science and technology Co., Ltd.), ascorbic acid, citric acid and tartaric acid; the mutual solvent is diethylene glycol monoethyl ether; the cleanup additive is one of long-chain fatty alcohol polyoxyethylene ether, alkylphenol polyoxyethylene ether, fatty acid polyoxyethylene ester, polyoxyethylene alkylamine and polyoxyethylene alkylamide.
If the scale formation is seriously scaled, the dosage of the scale remover can be properly increased, the dosage of the organic heavy hydrocarbon solvent can be increased when the wax formation is serious, different scale removers can be selected according to different scale components, but when the stratum is not carbonated scale, active water is generally used as a spacer fluid.
4) And (4) keeping the postposition liquid near the perforation blasthole, cleaning the perforation blasthole and accelerating the flowback of the residual liquid after reaction.
The using amount of the postposition liquid is 4-5 m3The postposition liquid consists of the following materials in parts by weight:
80-90 parts of potassium chloride solution and 8-15 parts of cleanup additive;
the concentration of the potassium chloride solution is 2-3%;
the cleanup additive is one of polyoxyethylene fatty acid ester, polyoxyethylene alkylamine and polyoxyethylene alkylamide.
5) And (3) ejecting the pretreatment liquid, the front pad liquid, the main treatment liquid and the post liquid into the stratum by using the displacement liquid, wherein the displacement liquid is remained in the oil casing and does not damage the perforation blasthole. The dosage of the displacement fluid is the volume of the ground pipeline and the shaft, and 0.5m is added3。
For a water well, the displacement fluid is active water; for oil wells, the displacement fluid is crude oil or diesel oil.
Evaluation of the Performance of the Main treatment fluid System of the present invention
Retardation performance
To evaluate the retardation performance of the main treatment liquid, the following tests were performed:
grinding the rock debris into powder of 100 meshes, respectively weighing four parts of 50g, respectively placing the four parts in a certain amount of different acid solutions, and measuring the corrosion rates of the different acid solutions at a certain temperature and for a certain time to evaluate the retarding performance of the rock debris.
The results show that: the corrosion rate of the earth acid is high, but after reacting for 2 hours, the reaction of the earth acid and the rock debris is basically finished; h3PO4+ HF has a certain retarding capacity, but the total corrosion amount (10-12 h) is low; the main treatment fluid has high corrosion capacity and good retarding performance, and is favorable for deep acidizing of sandstone formations.
Corrosion inhibiting Properties
In the acidification process, the corrosion of acid liquor to metals can not only damage the ground and underground equipment, but also a large amount of iron ions corroded can form ferric hydroxide precipitates under certain conditions, thereby causing formation blockage and reducing the treatment effect.
Mentioned above and CLO2The corrosion inhibitor has special structure and corrosion performance, and a certain amount of special corrosion inhibitor diethylenetriamine pentamethylene phosphonic acid is added into the system. The corrosion inhibitor is divided into a cationic type and an anionic type according to the difference of corrosion inhibition mechanisms, wherein the cationic type has the function of enabling the corrosion inhibitor and the metal surface anode region to share an electron pair, and the chemical bond established in the way can stop the reaction in the region. The anion type corrosion inhibitor is mainly adsorbed on a cathode region under the action of electrostatic attraction to form a protective film to prevent the reaction in the region, and many acid solution corrosion inhibitors used at present have the functions of the two types of corrosion inhibitors.
Since different corrosion inhibitors have different corrosion inhibition effects, in order to correctly select and use the corrosion inhibitor to reduce corrosion, evaluation tests are carried out on the performance of the acid liquor corrosion inhibitor. According to the method for evaluating and testing acidification corrosion inhibition issued by the ministry, the indoor existing corrosion inhibitor is evaluated under static state, normal pressure and different temperatures, and the test result shows that the diethylenetriamine pentamethylene phosphonic acid has good corrosion inhibition effect, and when the using concentration is 0.1 percent, the corrosion rate is 110.51g/m from the original corrosion rate2H reduced to 19.88g/m2.h。
Iron ion stability Properties
At CLO2During the acidification process, the acid solution is very easy to dissolve the iron rust and metallic iron in the oil pipe and the iron-containing minerals in the stratum, such as pyrite (FeS)2) Siderite (FeCO)3) Chlorite [ FeAl6(SI4O10)(OH)8]And the like. The dissolved iron is firstly kept in the residual acid solution in a dissolved state, the solubility of iron ions is reduced along with the increase of the pH value of the residual acid, and the precipitation of ferric hydroxide colloid is generated to block the stratum to generate secondary damage and reduce the acidification effect.
The test method for evaluating the iron ion stabilizer is as follows: in the presence of Fe of about 10000mg/L3+CLO of2Adding stabilizer with different concentrations into the solution, and adding Na2CO3Adjusting pH value to required value, keeping constant temperature for 4 hr at different temperatures, and determining Fe in solution by colorimetry3+The concentration of (c).
Indoor experimental research shows that the iron ion stabilizer for HT215 acidification has a good stabilizing effect on iron ions, and in addition, ascorbic acid, citric acid and tartaric acid also have a certain iron ion stabilizing effect and can be selected according to actual conditions.
Compatibility of drugs
Compatibility of the main treatment fluid system of the present invention: all the additives used in the main treatment fluid are added into the system according to the using concentration and shaken up, and the mixture is kept still for 2 hours at the temperature of 50 ℃, so that the liquid system does not delaminate and precipitate.
Compatibility of the primary treatment fluid with formation fluids: the liquid system is mixed with formation water in Huachi, Nanliang and other places, and no precipitate is generated.
The above tests show that the main treatment liquid system of the present invention has better compatibility.
The main treatment fluid has better comprehensive performance and wide applicability to plugging removal and acidification in deep oil layers.
The first embodiment is as follows:
middle 4-22 wells, which were put on after fracturing Y9, initial daily production 12.31m35.65t of daily oil production and 54.9 percent of water content, and the daily liquid production is 4.68m before the measure32.01t of daily oil production and 48.2 percent of water. Analysis considers that the well is blocked by three reasons: first, formation junction CaCO3The scale causes blockage and scaling with the thickness of 20mm, wax, colloid and asphaltene are blocked, and gum arabic fracturing is carried out in the early stage, so that the residue content is high, and the effect after fracturing is not ideal.
The chlorine dioxide oil-water well production and injection increasing process for removing the blockage of the tight oil reservoir specifically comprises the following steps:
1) injecting pretreatment liquid from the casing, removing wax deposition, scaling and corrosive substances on the inner and outer surfaces of the shaft oil casing by using the pretreatment liquid,
the dosage of the pretreatment liquid is 2m3The pretreatment solution consists of the following materials in parts by weight: 20 diluted acid liquid, 5 paraffin remover, 1 osmotic wetting agent, 1 surfactant and 6 demulsifier.
The dilute acid solution consists of the following materials in parts by weight: hydrochloric acid 3 and hydrofluoric acid 2; the concentration of the hydrochloric acid is 5%, and the concentration of the hydrofluoric acid is 2%;
the paraffin remover is carbon tetrachloride; the osmotic wetting agent is a wetting agent SX-YTRSJL (available from Shanghai Shengxuan Biochemical industry Co., Ltd.); the surfactant is SX-YTQYEA (available from Shanghai Shengxuan biochemistry chemical Co., Ltd.); the demulsifier is a demulsifier MQ801 (available from Guangzhou vast Qing environmental protection science and technology Limited company).
2) Injecting front pad liquid from the casing, neutralizing and softening excessive divalent metal cation Ca in the stratum by using the front pad liquid2+、Mg2+(ii) a Etc. the dosage of the front cushion liquid is 3m3。
The front pad liquid consists of the following materials in parts by weight: potassium chloride solution 70, EDTA5, scale inhibitor 6; the concentration of the potassium chloride solution is 2%; the scale inhibitor is a CH-003 scale inhibition dispersant (sold by Gallery Chenghua chemical Co., Ltd.).
3) Pumping main treating fluid from the casing pipe, wherein the main treating fluid is 8m3The stratum is deblocked by using the main treatment fluid, and the reaction time is 2 hours after the main treatment fluid is pumped inThen, the next step is proceeded to.
The main treatment liquid consists of the following materials in parts by weight: 40 parts of chlorine dioxide solution, 30 parts of hydrochloric acid, 6 parts of an activator, 3 parts of a corrosion inhibitor, 6 parts of an iron ion stabilizer, 6 parts of a mutual solvent and 10 parts of a cleanup additive.
The concentration of the chlorine dioxide solution is 3000 ppm; the concentration of hydrochloric acid is 6 percent; the active agent is fatty alcohol polyoxyethylene ether sodium sulfate; the corrosion inhibitor is diethylenetriamine penta (methylene phosphonic acid); the iron ion stabilizer is an iron ion stabilizer for HT215 acidification (available from Shandong Feiteng Petroleum science and technology Co., Ltd.); the mutual solvent is diethylene glycol monoethyl ether; the drainage aid is long-chain fatty alcohol-polyoxyethylene ether.
4) Adding the postposition liquid 4m3The residual liquid is kept near the perforation blasthole to clean the perforation blasthole and accelerate the return discharge of the residual liquid after reaction.
The postposition liquid consists of the following materials in parts by weight: potassium chloride solution 80 and cleanup additive 8.
The concentration of the potassium chloride solution is 2 percent; the cleanup additive is one of polyoxyethylene fatty acid ester, polyoxyethylene alkylamine and polyoxyethylene alkylamide.
5) And (3) ejecting the pretreatment liquid, the front pad liquid, the main treatment liquid and the post liquid into the stratum by using the displacement liquid, wherein the displacement liquid is remained in the oil casing and does not damage the perforation blasthole. For wells, the displacement fluid is activated water. The dosage of the displacement liquid is 8m3。
After the measures, the daily oil production of the well reaches 14.6 tons, the daily oil increase reaches 11.53 tons, and obvious effects are obtained
Example two:
north 59-4 wells, fracturing and production, and 5.4m of daily production fluid at initial stage33.82t of daily oil and 15.8 percent of water. The well has relatively poor physical property, other production increasing measures are not carried out since the production is put into operation, the well shaft is found to be seriously scaled during treatment, carbonate scales are taken as main components, the water content of the well shaft is always low, and certain organic matter blockage such as wax, colloid, asphaltene and the like exists.
The chlorine dioxide oil-water well production and injection increasing process for removing the blockage of the tight oil reservoir specifically comprises the following steps:
1) and removing wax precipitation, scaling and corrosive substances on the inner surface and the outer surface of the shaft oil casing by using the pretreatment liquid.
The dosage of the pretreatment liquid is 3m3The pretreatment solution consists of the following materials in parts by weight: 50 parts of dilute acid liquid, 10 parts of paraffin remover, 5 parts of osmotic wetting agent, 4 parts of surfactant and 10 parts of demulsifier.
The dilute acid solution consists of the following materials in parts by weight: hydrochloric acid 7 and hydrofluoric acid 5; the concentration of the hydrochloric acid is 8 percent, and the concentration of the hydrofluoric acid is 3 percent;
the paraffin remover is solvent oil; the osmotic wetting agent is a wetting agent SX-YTRSJL (available from Shanghai Shengxuan biochemistry chemical Co., Ltd.); the surfactant is SX-YTQYEA (sold by Shanghai Shengxuan biochemical engineering Co., Ltd.); the demulsifier is a demulsifier MQ801 (available from Guangzhou vast clean environmental protection science and technology Limited company).
2) Neutralizing and softening excessive divalent metal cation Ca of stratum by using front pad liquid2+、Mg2+(ii) a Etc. the dosage of the front cushion liquid is 4m3。
The front pad liquid consists of the following materials in parts by weight: potassium chloride solution 80, EDTA10, scale inhibitor 10; the concentration of the potassium chloride solution is 7%; the scale inhibitor is a CH-003 scale inhibition dispersant (sold by Gallery Chenghua chemical Co., Ltd.).
3) The stratum is deblocked by using main treatment fluid, wherein the main treatment fluid is 10m3Pumping the main treatment liquid, reacting for 3 hours, and then entering the next step;
the main treatment liquid consists of the following materials in parts by weight: 50 parts of chlorine dioxide solution, 40 parts of hydrochloric acid, 10 parts of an active agent, 7 parts of a corrosion inhibitor, 8 parts of an iron ion stabilizer, 10 parts of a mutual solvent and 15 parts of a cleanup additive.
The concentration of the chlorine dioxide solution is 3000 ppm; the concentration of hydrochloric acid is 8%; the active agent is sodium dodecyl sulfate; the corrosion inhibitor is potassium fluoride; the iron ion stabilizer is ascorbic acid; the mutual solvent is diethylene glycol monoethyl ether; the cleanup additive is polyoxyethylene alkylamide.
4) Adding the postposition liquid 5m3Remaining near the perforation hole, cleaning the perforation hole and accelerating the perforation holeAnd (4) returning and discharging residual liquid after reaction.
The postposition liquid consists of the following materials in parts by weight: potassium chloride solution 90, cleanup additive 15; the concentration of the potassium chloride solution is 3 percent; the cleanup additive is polyoxyethylene alkylamide.
5) And (3) ejecting the pretreatment liquid, the front pad liquid, the main treatment liquid and the post liquid into the stratum by using the displacement liquid, wherein the displacement liquid is remained in the oil casing and does not damage the perforation blasthole. The displacement fluid is diesel oil. The usage amount of the displacement liquid is 10.5m3。
After the blockage removing measures are adopted, the daily production liquid of the well is 10.32m3The daily oil yield is 5.36t, and the oil yield is 306t in the year.
The invention relates to a compact oil reservoir chlorine dioxide oil-water well production and injection increasing process, which oxidizes oleophylic sulfurous ferrous oxide into hydrophilic ferric oxide hydrate, and the chlorine dioxide is chelated by an additive in the acid; chlorine dioxide will also oxidize H produced by the reaction of ferrous sulfide with acid2S to reduce H2S can corrode the oil casing, and can also oxidize biological organic matter residues and vegetable gum fracturing fluid residues, and micelle agent and mutual solvent in the treatment fluid can dissolve heavy hydrocarbon remained in rock pores, and the heavy hydrocarbon can be used as a bonding agent for reaction residues, so that secondary pollution is effectively prevented, and the acidification blockage removal effect is improved.
The above description is only an embodiment of the present invention, and not intended to limit the scope of the present invention, and all modifications made by equivalent structures or equivalent processes, or directly or indirectly applied to other related technical fields, which are all included in the present invention.
Claims (1)
1. A chlorine dioxide oil-water well production and injection increasing process for a compact oil reservoir is characterized in that:
1) removing wax precipitation, scaling and corrosive substances on the inner surface and the outer surface of a shaft oil sleeve by using pretreatment liquid;
in the step 1), the pretreatment solution consists of the following materials in parts by weight:
20-50 parts of dilute acid liquid, 5-10 parts of paraffin remover, 1-5 parts of osmotic wetting agent, 1-4 parts of surfactant and 6-10 parts of demulsifier;
the dilute acid solution consists of the following materials in parts by weight:
3-7 parts of hydrochloric acid and 2-5 parts of hydrofluoric acid; the mass concentration of the hydrochloric acid is 5-8%, and the mass concentration of the hydrofluoric acid is 2-3%;
the paraffin remover is one of carbon tetrachloride, benzene, toluene and solvent oil;
the penetrating wetting agent is SX-YTRSJL wetting agent;
the surfactant is SX-YTQYEA;
the demulsifier is MQ801 demulsifier;
2) neutralizing and softening excessive divalent metal cation Ca of stratum by using front pad liquid2+、Mg2+；
In the step 2), the front pad liquid consists of the following materials in parts by weight:
70-80 parts of potassium chloride solution, 5-10 parts of EDTA and 6-10 parts of scale inhibitor;
the mass concentration of the potassium chloride solution is 2-7%;
the scale inhibitor is a CH-003 scale inhibition dispersant;
3) removing the blockage of the stratum by using the main treatment fluid;
in the step 3), the main treatment liquid consists of the following materials in parts by weight:
40-50 parts of chlorine dioxide solution, 30-40 parts of hydrochloric acid, 6-10 parts of active agent, 3-7 parts of corrosion inhibitor, 6-8 parts of iron ion stabilizer, 6-10 parts of mutual solvent and 10-15 parts of cleanup additive;
the concentration of the chlorine dioxide solution is 3000 ppm;
the mass concentration of the hydrochloric acid is 6-8%;
the active agent is fatty alcohol polyoxyethylene ether sodium sulfate or lauryl sodium sulfate;
the corrosion inhibitor is diethylenetriamine pentamethylene phosphonic acid, hydroxyl ethylidene diphosphonic acid, sodium nitrate, potassium fluoride or sodium tripolyphosphate;
the iron ion stabilizer is an iron ion stabilizer for HT215 acidification, ascorbic acid, citric acid or tartaric acid;
the mutual solvent is diethylene glycol monoethyl ether;
the cleanup additive is one of long-chain fatty alcohol-polyoxyethylene ether, alkylphenol ethoxylate, fatty acid-polyoxyethylene ester, polyoxyethylene alkylamine and polyoxyethylene alkylamide;
4) keeping the postposition liquid near the perforation blasthole and cleaning the perforation blasthole;
in the step 4), the postposition liquid consists of the following materials in parts by weight:
80-90 parts of potassium chloride solution and 8-15 parts of cleanup additive;
the mass concentration of the potassium chloride solution is 2-3%;
the cleanup additive is one of polyoxyethylene fatty acid ester, polyoxyethylene alkylamine and polyoxyethylene alkylamide;
5) ejecting the pretreatment liquid, the front pad liquid, the main treatment liquid and the post-treatment liquid into the stratum by using a displacement liquid, and retaining the displacement liquid in the oil casing;
in the step 5), for a water well, the displacement liquid is active water; for oil wells, the displacement fluid is crude oil or diesel oil.
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