CN114427401A - Method for improving oil reservoir recovery ratio by changing oil reservoir wettability through microorganisms - Google Patents
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- 238000000034 method Methods 0.000 title claims abstract description 101
- 238000011084 recovery Methods 0.000 title claims abstract description 62
- 244000005700 microbiome Species 0.000 title claims abstract description 43
- 239000012190 activator Substances 0.000 claims abstract description 129
- 238000009736 wetting Methods 0.000 claims abstract description 128
- 238000012216 screening Methods 0.000 claims abstract description 124
- 238000012360 testing method Methods 0.000 claims abstract description 91
- 230000008859 change Effects 0.000 claims abstract description 57
- 238000002347 injection Methods 0.000 claims abstract description 57
- 239000007924 injection Substances 0.000 claims abstract description 57
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 52
- 230000003213 activating effect Effects 0.000 claims abstract description 51
- 230000001580 bacterial effect Effects 0.000 claims abstract description 30
- 230000003068 static effect Effects 0.000 claims abstract description 23
- 238000004088 simulation Methods 0.000 claims abstract description 18
- 230000006872 improvement Effects 0.000 claims abstract description 16
- 230000000694 effects Effects 0.000 claims abstract description 10
- 238000012136 culture method Methods 0.000 claims abstract description 9
- 239000003921 oil Substances 0.000 claims description 256
- 235000019198 oils Nutrition 0.000 claims description 249
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 64
- 239000011435 rock Substances 0.000 claims description 63
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 56
- OAICVXFJPJFONN-UHFFFAOYSA-N Phosphorus Chemical compound [P] OAICVXFJPJFONN-UHFFFAOYSA-N 0.000 claims description 29
- 239000010779 crude oil Substances 0.000 claims description 29
- 229910052698 phosphorus Inorganic materials 0.000 claims description 29
- 239000011574 phosphorus Substances 0.000 claims description 29
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 claims description 28
- 229910052799 carbon Inorganic materials 0.000 claims description 28
- 229910052757 nitrogen Inorganic materials 0.000 claims description 28
- 239000007788 liquid Substances 0.000 claims description 24
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 claims description 22
- 239000008398 formation water Substances 0.000 claims description 20
- 239000000203 mixture Substances 0.000 claims description 17
- JVTAAEKCZFNVCJ-UHFFFAOYSA-N lactic acid Chemical compound CC(O)C(O)=O JVTAAEKCZFNVCJ-UHFFFAOYSA-N 0.000 claims description 16
- 230000033558 biomineral tissue development Effects 0.000 claims description 15
- 230000035699 permeability Effects 0.000 claims description 15
- 235000012054 meals Nutrition 0.000 claims description 14
- KDYFGRWQOYBRFD-UHFFFAOYSA-N Succinic acid Natural products OC(=O)CCC(O)=O KDYFGRWQOYBRFD-UHFFFAOYSA-N 0.000 claims description 13
- 235000012343 cottonseed oil Nutrition 0.000 claims description 13
- ZPWVASYFFYYZEW-UHFFFAOYSA-L dipotassium hydrogen phosphate Chemical compound [K+].[K+].OP([O-])([O-])=O ZPWVASYFFYYZEW-UHFFFAOYSA-L 0.000 claims description 13
- 229910000402 monopotassium phosphate Inorganic materials 0.000 claims description 13
- 235000019796 monopotassium phosphate Nutrition 0.000 claims description 13
- 229920006395 saturated elastomer Polymers 0.000 claims description 13
- 238000005406 washing Methods 0.000 claims description 13
- 239000011148 porous material Substances 0.000 claims description 12
- 239000000243 solution Substances 0.000 claims description 11
- 239000004310 lactic acid Substances 0.000 claims description 8
- 235000014655 lactic acid Nutrition 0.000 claims description 8
- 241000193752 Bacillus circulans Species 0.000 claims description 7
- 241000194105 Paenibacillus polymyxa Species 0.000 claims description 7
- KDYFGRWQOYBRFD-NUQCWPJISA-N butanedioic acid Chemical compound O[14C](=O)CC[14C](O)=O KDYFGRWQOYBRFD-NUQCWPJISA-N 0.000 claims description 7
- 238000012258 culturing Methods 0.000 claims description 7
- PJNZPQUBCPKICU-UHFFFAOYSA-N phosphoric acid;potassium Chemical compound [K].OP(O)(O)=O PJNZPQUBCPKICU-UHFFFAOYSA-N 0.000 claims description 6
- 238000009738 saturating Methods 0.000 claims description 5
- 235000017060 Arachis glabrata Nutrition 0.000 claims description 4
- 244000105624 Arachis hypogaea Species 0.000 claims description 4
- 235000010777 Arachis hypogaea Nutrition 0.000 claims description 4
- 235000018262 Arachis monticola Nutrition 0.000 claims description 4
- 241000193747 Bacillus firmus Species 0.000 claims description 4
- 241000194103 Bacillus pumilus Species 0.000 claims description 4
- 244000063299 Bacillus subtilis Species 0.000 claims description 4
- 235000014469 Bacillus subtilis Nutrition 0.000 claims description 4
- 235000019779 Rapeseed Meal Nutrition 0.000 claims description 4
- 229940005348 bacillus firmus Drugs 0.000 claims description 4
- 238000011156 evaluation Methods 0.000 claims description 4
- 235000020232 peanut Nutrition 0.000 claims description 4
- 239000004456 rapeseed meal Substances 0.000 claims description 4
- 238000011065 in-situ storage Methods 0.000 claims description 3
- 230000002708 enhancing effect Effects 0.000 claims 3
- 238000005259 measurement Methods 0.000 claims 1
- 238000011161 development Methods 0.000 abstract description 6
- 230000008569 process Effects 0.000 abstract description 5
- LWIHDJKSTIGBAC-UHFFFAOYSA-K potassium phosphate Substances [K+].[K+].[K+].[O-]P([O-])([O-])=O LWIHDJKSTIGBAC-UHFFFAOYSA-K 0.000 description 13
- 230000004913 activation Effects 0.000 description 11
- 239000000843 powder Substances 0.000 description 9
- 241000894006 Bacteria Species 0.000 description 8
- 238000009472 formulation Methods 0.000 description 7
- GNSKLFRGEWLPPA-UHFFFAOYSA-M potassium dihydrogen phosphate Chemical compound [K+].OP(O)([O-])=O GNSKLFRGEWLPPA-UHFFFAOYSA-M 0.000 description 7
- 229910000396 dipotassium phosphate Inorganic materials 0.000 description 6
- 235000019797 dipotassium phosphate Nutrition 0.000 description 6
- 240000002791 Brassica napus Species 0.000 description 5
- 235000004977 Brassica sinapistrum Nutrition 0.000 description 5
- 230000001186 cumulative effect Effects 0.000 description 5
- 230000018109 developmental process Effects 0.000 description 5
- 238000003306 harvesting Methods 0.000 description 5
- 239000004094 surface-active agent Substances 0.000 description 5
- 229920000742 Cotton Polymers 0.000 description 4
- 239000012530 fluid Substances 0.000 description 4
- KWIUHFFTVRNATP-UHFFFAOYSA-N glycine betaine Chemical compound C[N+](C)(C)CC([O-])=O KWIUHFFTVRNATP-UHFFFAOYSA-N 0.000 description 4
- 239000000080 wetting agent Substances 0.000 description 4
- 230000008901 benefit Effects 0.000 description 3
- 235000013312 flour Nutrition 0.000 description 3
- -1 polyoxyethylene Polymers 0.000 description 3
- 238000012163 sequencing technique Methods 0.000 description 3
- 239000000126 substance Substances 0.000 description 3
- 239000001384 succinic acid Substances 0.000 description 3
- 108010028921 Lipopeptides Proteins 0.000 description 2
- 229920003171 Poly (ethylene oxide) Polymers 0.000 description 2
- 150000003973 alkyl amines Chemical class 0.000 description 2
- 229960003237 betaine Drugs 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 239000002736 nonionic surfactant Substances 0.000 description 2
- 229920000056 polyoxyethylene ether Polymers 0.000 description 2
- 229940051841 polyoxyethylene ether Drugs 0.000 description 2
- 239000000244 polyoxyethylene sorbitan monooleate Substances 0.000 description 2
- 235000010482 polyoxyethylene sorbitan monooleate Nutrition 0.000 description 2
- 229920000053 polysorbate 80 Polymers 0.000 description 2
- 241000635201 Pumilus Species 0.000 description 1
- 239000002253 acid Substances 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 239000011218 binary composite Substances 0.000 description 1
- 239000003876 biosurfactant Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 230000007547 defect Effects 0.000 description 1
- 238000000572 ellipsometry Methods 0.000 description 1
- 239000003995 emulsifying agent Substances 0.000 description 1
- 238000003912 environmental pollution Methods 0.000 description 1
- 238000000605 extraction Methods 0.000 description 1
- 235000019387 fatty acid methyl ester Nutrition 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- 239000001257 hydrogen Substances 0.000 description 1
- IIXGBDGCPUYARL-UHFFFAOYSA-N hydroxysulfamic acid Chemical compound ONS(O)(=O)=O IIXGBDGCPUYARL-UHFFFAOYSA-N 0.000 description 1
- MTNDZQHUAFNZQY-UHFFFAOYSA-N imidazoline Chemical compound C1CN=CN1 MTNDZQHUAFNZQY-UHFFFAOYSA-N 0.000 description 1
- 230000008595 infiltration Effects 0.000 description 1
- 238000001764 infiltration Methods 0.000 description 1
- 230000007774 longterm Effects 0.000 description 1
- 229910021645 metal ion Inorganic materials 0.000 description 1
- 235000013557 nattō Nutrition 0.000 description 1
- 231100000252 nontoxic Toxicity 0.000 description 1
- 230000003000 nontoxic effect Effects 0.000 description 1
- 239000003129 oil well Substances 0.000 description 1
- 239000002244 precipitate Substances 0.000 description 1
- 230000001681 protective effect Effects 0.000 description 1
- 230000001105 regulatory effect Effects 0.000 description 1
- 150000003839 salts Chemical class 0.000 description 1
- 239000010865 sewage Substances 0.000 description 1
- CDBYLPFSWZWCQE-UHFFFAOYSA-L sodium carbonate Substances [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 description 1
- 229910000029 sodium carbonate Inorganic materials 0.000 description 1
- IIACRCGMVDHOTQ-UHFFFAOYSA-N sulfamic acid Chemical compound NS(O)(=O)=O IIACRCGMVDHOTQ-UHFFFAOYSA-N 0.000 description 1
Classifications
-
- 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
-
- 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
- E21B47/00—Survey of boreholes or wells
Abstract
The invention belongs to the technical field of oilfield development, and particularly relates to a method for improving oil reservoir recovery efficiency by changing oil reservoir wettability through microorganisms. The method comprises the following steps: screening a test oil reservoir, wherein the screening standard comprises that the wetting contact angle of an oil phase of the test oil reservoir is less than 70 degrees and wettability-changing microorganisms exist in the oil reservoir; the method comprises the following steps of (1) primarily screening an activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of a wettability microorganism; screening an activator, namely screening the activator on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of an oil phase wetting contact angle; and determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value. The method has the characteristics of simple process and good field test effect, the field test improves the recovery ratio by more than 20 percent, the input-output ratio is more than 1:15, and the validity period is more than 5 years.
Description
Technical Field
The invention belongs to the technical field of oilfield development, and particularly relates to a method for improving oil reservoir recovery efficiency by changing oil reservoir wettability through microorganisms.
Background
In oil reservoir development, waterflooding development is a main mode for improving recovery efficiency, and factors influencing waterflooding development are many. According to microscopic level analysis, the surface of the oil deposit rock is often oleophilic due to long-term infiltration by crude oil, so that the crude oil has large capillary resistance and poor fluidity in the circulation process. Therefore, if the lithology of the rock surface of the oil reservoir can be regulated and controlled to be inverted into hydrophilic or weak hydrophilic, the flow resistance of crude oil is greatly reduced, and the water drive efficiency is greatly improved. Therefore, screening for suitable wetting reversers is key to improving the development benefit.
CN101892040B discloses a wetting agent and application thereof in binary combination flooding tertiary oil recovery, wherein the wetting agent is composed of sulfoamide betaine, alkylamide hydroxysulfoamide betaine, sulfonic imidazoline, fatty alcohol-polyoxyethylene ether, polyoxyethylene sorbitan monooleate, polyoxyethylene alkylamine, fatty acid methyl ester ethoxylate and auxiliary emulsifier. The wetting agent prepared by the method can convert oleophylic oil layer into strong water-wet oil layer in the binary composite flooding process, and can greatly improve the oil layer recovery ratio. When the binary compound flooding oil extraction is carried out, the reservoir is converted from oleophylic to hydrophilic, and the ultimate recovery rate can be improved by 10.47 percent. However, due to the use of non-temperature-resistant nonionic surfactants such as fatty alcohol-polyoxyethylene ether, polyoxyethylene sorbitan monooleate, polyoxyethylene alkylamine and the like, the surfactants are easy to separate out of the solution after the oil deposit temperature is higher than 80 ℃ (higher than the cloud point temperature of the nonionic surfactant), and the performance of the wetting agent is affected, so that the surfactant is not suitable for high-temperature oil deposits.
The university scholars of Sudan Kabusi H.Al-Sulaimann discloses a method for improving the residual oil recovery ratio of a thin oil reservoir by using lipopeptide biosurfactant (SPE 158022), wherein lipopeptide with the concentration of 0.25 percent and Na with the concentration of 0.25 percent are injected after one-dimensional tubular model is subjected to water flooding2CO3After the solution is mixed, the recovery rate is improved by 25 percent, and simultaneously the contact angle is reduced from 70.6 degrees to 25.32 degrees. The biological surfactant has excellent temperature resistance, so that the temperature resistance problem of the surfactant is effectively solved, and the biological surfactant has potential for use in high-temperature oil reservoirs. But because of the use of weak base Na2CO3The substance is very easy to react with divalent metal ion Ca in oil reservoirs with high mineralization degree2+、Mg2+Precipitates are generated in the reaction, scaling is caused to damage the oil reservoir, and therefore the high-salinity oil reservoir is not suitable for use.
At present, a chemical method is adopted for wetting reversal of an oil reservoir, and has the problems of high treatment cost, poor oil reservoir adaptability, environmental pollution and difficult subsequent sewage treatment.
Disclosure of Invention
The invention aims to overcome the defects of the prior art and provide a method for improving the recovery ratio of an oil reservoir by changing the wettability of the oil reservoir by using microorganisms. The method has the advantages of strong oil reservoir adaptability, high temperature and high salt resistance, low treatment cost and simple treatment process; injecting an activator into an oil well to activate functional microorganisms for changing the wettability of the oil reservoir to act on the oleophilic rock surface of the oil reservoir, changing the oleophilic rock into hydrophilic rock so as to realize the reversal of the wettability, and stripping crude oil from the rock surface, thereby greatly improving the crude oil recovery rate of the oil reservoir.
In order to achieve the above object, the present invention discloses a method for improving oil reservoir recovery by changing oil reservoir wettability with a microorganism, comprising the steps of:
(1) and (3) testing the screening of the oil reservoir, wherein the screening standard comprises that the oil phase wetting contact angle of the oil reservoir is less than 70 degrees and microorganisms for changing wettability exist in the oil reservoir.
(2) And (3) primarily screening the activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of the wettability microorganism.
(3) And (3) screening the activating agent, namely screening the activating agent on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of the wetting contact angle of the oil phase.
(4) And determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value.
Compared with the prior art, the invention has the following advantages:
(1) the invention has wide application range of oil reservoirs, is suitable for medium-low permeability oil reservoirs and medium-high temperature high salinity oil reservoirs;
(2) the injected activating agent is non-toxic and harmless to human bodies, so that the problems of damage to stratum and pollution to environment are avoided, and the problem of subsequent water treatment caused by a chemical method is avoided;
(3) the invention utilizes the functional microorganism for changing the wettability of the oil reservoir to act on the oleophilic rock surface of the oil reservoir to realize the reversion of the wettability, changes the wettability of the rock from oleophilic to hydrophilic, and has a large change degree of a wetting contact angle which is more than 60 degrees;
(4) the method has the characteristics of simple process, strong operability and good field test effect, the field test improves the recovery ratio by more than 20 percent, the input-output ratio is more than 1:15, and the validity period is more than 5 years.
Detailed Description
The endpoints of the ranges and any values disclosed herein are not limited to the precise range or value, and such ranges or values should be understood to encompass values close to those ranges or values. For ranges of values, between the endpoints of each of the ranges and the individual points, and between the individual points may be combined with each other to give one or more new ranges of values, and these ranges of values should be considered as specifically disclosed herein.
According to an object of the present invention, there is disclosed a method for increasing oil recovery by changing wettability of an oil reservoir using a microorganism, the method comprising the steps of:
(1) and (3) testing the screening of the oil reservoir, wherein the screening standard comprises that the oil phase wetting contact angle of the oil reservoir is less than 70 degrees and microorganisms for changing wettability exist in the oil reservoir.
(2) And (3) primarily screening the activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of the wettability microorganism.
(3) And (3) screening the activating agent, namely screening the activating agent on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of the wetting contact angle of the oil phase.
(4) And determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value.
In the invention, the screening standard of the test oil reservoir further comprises: oil reservoir permeability less than or equal to 2000 x 10-3μm2The oil reservoir temperature is less than or equal to 90 ℃, the crude oil viscosity is less than or equal to 20000mPa.s, and the formation water mineralization is less than or equal to 150000 mg/L. More preferably, the oil reservoir permeability is less than or equal to 1000 multiplied by 10-3μm2The oil reservoir temperature is less than or equal to 70 ℃, the crude oil viscosity is less than or equal to 10000mPa.s, and the formation water mineralization is less than or equal to 50000 mg/L.
Preferably, the microorganism for changing the wettability is one or more of bacillus natto, bacillus polymyxa, bacillus firmus, bacillus pumilus and bacillus circulans. More preferably, Bacillus polymyxa or Bacillus circulans.
In the present invention, preferably, the specific steps of the primary screening of the activator are as follows: taking a 100mL conical flask, adding 60-80 mL of produced liquid of a test oil reservoir, and adding an activating agent; then placing the mixture at the temperature of the oil reservoir to be tested for culturing for 10-30 d; and (3) determining the bacterial concentration of the wettability-changing microorganisms in the culture solution, and primarily screening 2-3 groups of activating agent formulas with higher bacterial concentration according to the bacterial concentration.
In the present invention, preferably, the specific steps of the activator screening are as follows: firstly, washing oil from a natural rock core of a test oil reservoir to prepare a standard rock core with phi 25 multiplied by 100mm, measuring an initial oil phase wetting contact angle of the rock core, then injecting a preliminarily screened activating agent formula, and performing static culture for 5-10 days; then measuring an oil phase wetting contact angle after the core activator is treated; and finally, screening the activator corresponding to the rock core with the largest change degree of the wetting contact angle as the screened activator.
In the present invention, preferably, the injection amount determination comprises the following specific steps: firstly, washing oil from a natural core of a test oil reservoir to prepare a standard core with phi 25 multiplied by 100mm, measuring an initial oil phase contact angle of the core, vacuumizing the core, saturating formation water of the test oil reservoir, and measuring PV (pore volume) of the core; measuring the amount of saturated crude oil until the crude oil of the oil reservoir is saturated until the produced liquid contains 100% of oil, and calculating the original oil saturation of the core; performing primary water flooding until the water content of produced liquid is consistent with the current comprehensive water content of the test oil reservoir; secondly, injecting activating agents with different volume amounts, and performing static culture for 10-30 d; finally, performing secondary water flooding until the water content of the produced liquid is 100%; measuring the oil phase wetting contact angle after the rock core is treated and calculating the improved recovery value; and finally, screening out the injection quantity of the activator corresponding to the rock core with the largest wetting contact angle change degree and the largest recovery rate improvement value as the field injection quantity.
Preferably, the wetting contact angle is measured by one of a tangent method, a circle method, an ellipse method and a Laplace-Young method, and more preferably, by a tangent method or a circle method.
In the present invention, preferably, the method further comprises field test and effect evaluation.
Preferably, the field test is a continuous injection of the activator from the injection well of the test reservoir using a high pressure plunger pump.
Preferably, the evaluation indexes of the effect are effective period, enhanced recovery degree and input-output ratio.
In the invention, preferably, the activator consists of a carbon source, a nitrogen source and a phosphorus source, wherein the carbon source is one of succinic acid, lactic acid and ethanol, the nitrogen source is one of cottonseed flour, rapeseed cake flour and peanut flour, and the phosphorus source is dipotassium hydrogen phosphate or potassium dihydrogen phosphate.
Preferably, the mass concentrations of the activator carbon source, the activator nitrogen source and the activator phosphorus source are 1.0 to 5.0%, 0.1 to 0.6% and 0.01 to 0.08%, more preferably 2.0 to 3.0%, 0.3 to 0.5% and 0.02 to 0.03%, respectively.
Preferably, the in situ injection amount is 0.1-0.5PV, more preferably 0.2-0.3 PV.
In the present invention, it is preferable that the activator is injected in situ at a rate of 5 to 15m3H, more preferably 8 to 12m3/h。
The preferred embodiments of the present invention have been described in detail, however, the present invention is not limited to the specific details of the above embodiments, and various simple modifications may be made to the technical solution of the present invention within the technical idea of the present invention, and these simple modifications are within the protective scope of the present invention.
It should be noted that the various technical features described in the above embodiments can be combined in any suitable manner without contradiction, and the invention is not described in any way for the possible combinations in order to avoid unnecessary repetition.
In addition, any combination of the various embodiments of the present invention is also possible, and the same should be considered as the disclosure of the present invention as long as it does not depart from the spirit of the present invention.
The present invention will be further described with reference to specific examples.
Example 1:
summary of the test reservoirs: victory oil field certain block D12The oil reservoir temperature is 62 ℃, the ground viscosity of crude oil is 1258 mPa.s, the formation water mineralization is 9765mg/L, and the permeability is 950 multiplied by 10-3μm2Stratum pressure 11.2MPa, geological reserve 2.0X 104t, pore volume 5.0X 105m3. Before the test, the comprehensive water content of the block is 98.8%. The tested block has a phase wetting contact angle of 35 degrees, and the existence of Bacillus natto of 2.0 multiplied by 10 in the formation water2One per ml. The method of the present invention is implemented in the block, and the specific steps are as follows:
(1) and (3) testing the screening of the oil reservoir, wherein the screening standard comprises that the oil phase wetting contact angle of the oil reservoir is less than 70 degrees and microorganisms for changing wettability exist in the oil reservoir.
The test reservoir D12The oil deposit temperature is 62 ℃, the ground viscosity of crude oil is 1258 mPa.s, the formation water mineralization is 9765mg/L, and the permeability is 950 multiplied by 10-3μm2Bacillus natto (2.0 × 10) exists in stratum water2Piece/ml, phase wetting contact angle 35 °. The present invention may be practiced in compliance with the screening criteria of the present invention.
(2) And (3) primarily screening the activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of the wettability microorganism.
The specific steps of the primary screening of the activating agent are as follows: 100mL Erlenmeyer flask was taken and 60mL test reservoir D was added12Adding an activating agent into the produced liquid (see table 1); then placing the mixture at the temperature of 62 ℃ for culturing for 10d at the temperature of a test oil reservoir; and (3) measuring the bacterial concentration of the bacillus natto in the culture solution, wherein the measuring result is shown in table 1, and 2-3 groups of activator formulas with higher bacterial concentration are preliminarily screened according to the bacterial concentration.
TABLE 1 concentration of activated bacteria of different activators and sequencing results
As can be seen from Table 1, the concentrations of the activated activators formula I, formula III and formula IV are higher and are all larger than 1.0X 108One/ml, therefore, preliminaryThe screened activating agents comprise a formula I (carbon source: 2.0% of succinic acid, nitrogen source: 0.5% of cottonseed meal, phosphorus source: 0.06% of dipotassium phosphate), a formula III (carbon source: 4.0% of ethanol, nitrogen source: 0.6% of cottonseed meal, phosphorus source: 0.01% of monopotassium phosphate) and a formula IV (carbon source: 5.0% of succinic acid, nitrogen source: 0.1% of rapeseed cake meal, phosphorus source: 0.05% of dipotassium phosphate).
(3) And (3) screening the activating agent, namely screening the activating agent on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of the wetting contact angle of the oil phase.
The specific steps of the activator screening are as follows: first, the reservoir D is tested12Washing oil from the natural rock core to prepare a standard rock core with phi 25 multiplied by 100mm, measuring the initial oil phase wetting contact angle of the rock core, and injecting an activating agent formula for preliminary screening, and performing static culture for 5 d; then measuring the wetting contact angle of the oil phase after the treatment of the core activator, and the test result is shown in table 2; and finally, screening the activator corresponding to the rock core with the largest change degree of the wetting contact angle as the screened activator.
TABLE 2 wetting contact angle test results of rock oil phase before and after activation with different activators
As can be seen from Table 2, the wetting angles of the oil phases of the tested oil reservoir rocks are obviously changed from oil wetting to water wetting after the activation of the first, third and fourth formulas, wherein the largest change is that the wetting contact angle is changed to 67 degrees according to the third formula (carbon source: 4.0% of ethanol, nitrogen source: 0.6% of cottonseed meal, phosphorus source: 0.01% of monopotassium phosphate), and therefore, the formula of the screened activator is the carbon source: ethanol 4.0 wt%, nitrogen source: 0.6 wt% of cotton seed powder, phosphorus source: potassium dihydrogen phosphate 0.01 wt%.
The wetting contact angle was measured by the tangent method.
(4) And determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value.
The injection amount determination method comprises the following specific steps: first, the reservoir D is tested12Washing oil from natural core to obtain standard core with diameter of 25X 100mm, measuring initial oil phase contact angle of core, vacuumizing core, and saturating oil reservoir D12The PV (pore volume) of the core is determined; measuring the amount of saturated crude oil until the crude oil of the oil reservoir is saturated until the produced liquid contains 100% of oil, and calculating the original oil saturation of the core; performing primary water flooding until the water content of produced liquid is consistent with the current comprehensive water content of the test oil reservoir; secondly, injecting activating agents with different volume amounts (see table 3), and carrying out static culture for 10 d; finally, performing secondary water flooding until the water content of the produced liquid is 100%; measuring the oil phase wetting contact angle after core treatment and calculating the enhanced recovery value (see table 3); and finally, screening out the injection quantity of the activator corresponding to the rock core with the largest wetting contact angle change degree and the largest recovery rate improvement value as the field injection quantity.
TABLE 3 degree of wetting angle change and enhanced recovery for different amounts of activators
| Serial number | Amount of activator injected, PV | Degree of change of wetting angle ° | Increase the harvest rate% |
| 1 | 0.1 | 35 | 15.3 |
| 2 | 0.2 | 54 | 18.8 |
| 3 | 0.3 | 72 | 25.6 |
| 4 | 0.4 | 63 | 21.5 |
| 5 | 0.5 | 58 | 20.7 |
As can be seen from table 3, the oil phase wetting angle change degree and the yield increase value of the core are different according to the injection amount of the activator, and the oil phase wetting angle change degree and the yield increase value of the core are respectively the largest when the injection amount of the activator is 0.3PV, and are respectively 72 ° and 25.6%, so that the optimal injection amount of the activator in the field is selected to be 0.3 PV.
In the block D12Injecting activator 1.5 × 105m3The field injection speed of the activator is 5m3/h。
And (3) evaluating field test results: the block D12The comprehensive water content is reduced to 62.0 percent from 98.8 percent before implementation, the water content is reduced to 36.6 percent, and the cumulative oil increase is 0.45 multiplied by 10 by 6 months and 30 days by 20204t, improving the recovery ratio by 22.5%; the validity period is 6 years, the input-output ratio is 1:15.5, the field test effect is good, and the invention has wide popularization and application prospects.
Example 2
Summary of the test reservoirs: victory oil field certain block D15Temperature of reservoirCrude oil ground viscosity of 1652 mPa.s at 65 ℃, formation water mineralization of 9250mg/L and permeability of 800 x 10-3μm2Stratum pressure 11.0MPa, geological reserve 5.0X 104t, pore volume 2.0X 106m3. Before the test, the comprehensive water content of the block is 98.0%. The contact angle of the wetting phase of the tested block is 42 degrees, and the bacillus polymyxa exists in the formation water by 1.0 multiplied by 102One per ml. The method of the present invention is implemented in the block, and the specific steps are as follows:
(1) and (3) testing the screening of the oil reservoir, wherein the screening standard comprises that the oil phase wetting contact angle of the oil reservoir is less than 70 degrees and microorganisms for changing wettability exist in the oil reservoir.
The test reservoir D15Oil reservoir temperature 65 deg.c, crude oil ground viscosity 1652 mPa.s, stratum water mineralization 9250mg/L, permeability 800X 10-3μm2In the formation water, Bacillus polymyxa 1.0X 102Piece/ml, phase wetting contact angle 42 deg.. The present invention may be practiced in compliance with the screening criteria of the present invention.
(2) And (3) primarily screening the activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of the wettability microorganism.
The specific steps of the primary screening of the activating agent are as follows: 100mL Erlenmeyer flask was taken and 70mL test reservoir D was added15Adding an activating agent into the produced fluid (see table 4); then placing the mixture at the temperature of a test oil reservoir and culturing the mixture for 15d at 65 ℃; the bacterial concentration of the bacillus polymyxa in the culture solution is determined, the determination result is shown in table 4, and 2-3 groups of activator formulas with higher bacterial concentration are preliminarily screened according to the bacterial concentration.
TABLE 4 concentration of activated bacteria and sequencing results for different activators
As can be seen from Table 4, activator formulation oneThe concentration of the activated bacteria is higher than that of the activated bacteria in the formula II, and the concentration of the activated bacteria is more than 1.0 multiplied by 108Therefore, the formula of the preliminarily screened activators comprises formula I (carbon source: 2.0% succinic acid, nitrogen source: 0.5% cottonseed meal, phosphorus source: 0.06% dipotassium hydrogen phosphate) and formula II (carbon source: 1.0% lactic acid, nitrogen source: 0.2% rapeseed meal, phosphorus source: 0.03% dipotassium hydrogen phosphate).
(3) And (3) screening the activating agent, namely screening the activating agent on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of the wetting contact angle of the oil phase.
The specific steps of the activator screening are as follows: first, the reservoir D is tested15Washing oil from the natural rock core to prepare a standard rock core with phi 25 multiplied by 100mm, measuring the initial oil phase wetting contact angle of the rock core, and injecting an activating agent formula for preliminary screening, and performing static culture for 6 d; then measuring the wetting contact angle of the oil phase after the treatment of the core activator, and the test result is shown in table 5; and finally, screening the activator corresponding to the rock core with the largest change degree of the wetting contact angle as the screened activator.
TABLE 5 wetting contact Angle test results of the rock oil phase before and after activation with different activators
As can be seen from Table 5, the wetting angle of the oil phase of the oil reservoir rock tested after the activation of the formula I and the formula II is obviously changed from oil wetting to water wetting, wherein the largest change is that the wetting contact angle is changed to 72 degrees in the formula II (carbon source: 1.0% of lactic acid, nitrogen source: 0.2% of rapeseed cake powder, phosphorus source: 0.03% of dipotassium hydrogen phosphate), and therefore, the formula of the screened activator is the carbon source: lactic acid 1.0%, nitrogen source: 0.2% of rapeseed cake powder, and a phosphorus source: dipotassium phosphate 0.03%.
The wetting contact angle was measured by the circular method.
(4) And determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value.
The injection amount determination method comprises the following specific steps: first, the reservoir D is tested15Washing oil from natural core to obtain standard core with diameter of 25X 100mm, measuring initial oil phase contact angle of core, vacuumizing core, and saturating oil reservoir D15The PV (pore volume) of the core is determined; measuring the amount of saturated crude oil until the crude oil of the oil reservoir is saturated until the produced liquid contains 100% of oil, and calculating the original oil saturation of the core; performing primary water flooding until the water content of produced liquid is consistent with the current comprehensive water content of the test oil reservoir; secondly, injecting activating agents with different volume amounts (see table 6), and carrying out static culture for 15 d; finally, performing secondary water flooding until the water content of the produced liquid is 100%; measuring the oil phase wetting contact angle after core treatment and calculating the enhanced recovery value (see table 6); and finally, screening out the injection quantity of the activator corresponding to the rock core with the largest wetting contact angle change degree and the largest recovery rate improvement value as the field injection quantity.
TABLE 6 variation of wetting angle of oil phase of activators at different injection rates and enhanced recovery values
| Serial number | Amount of activator injected, PV | Degree of change of wetting angle ° | Increase the harvest rate% |
| 1 | 0.1 | 28 | 12.3 |
| 2 | 0.2 | 42 | 17.5 |
| 3 | 0.3 | 58 | 19.6 |
| 4 | 0.4 | 65 | 26.3 |
| 5 | 0.5 | 55 | 21.2 |
As can be seen from table 6, the oil phase wetting angle change degree and the yield increase value of the core are different according to the injection amount of the activator, and the oil phase wetting angle change degree and the yield increase value of the core are respectively the largest when the injection amount of the activator is 0.4PV, and are respectively 65 ° and 26.3%, so that the optimal injection amount of the activator in the field is selected to be 0.4 PV.
In the block D15Injecting activator 0.8 × 106m3The field injection speed of the activator is 10m3/h。
And (3) evaluating field test results: the block D15The comprehensive water content is reduced to 63.5 percent from 98.0 percent before implementation, the water content is reduced to 34.5 percent, and the cumulative oil increase is 1.16 multiplied by 10 by 30 days in 12 months and 30 days in 20194t, improving the recovery ratio by 23.2%; the validity period is 7 years, the input-output ratio is 1:17.3, the field test effect is good, and the invention has wide popularization and application prospects.
Example 3
Summary of the test reservoirs: victory oil field certain block E18Oil reservoir temperature 75 deg.C, crude oilGround viscosity 985 mPa.s, formation water mineralization 6785mg/L, permeability 1100 x 10-3μm2Stratum pressure 13.5MPa, geological reserve 3.2X 105t, pore volume 8.3X 106m3. Before the test, the comprehensive water content of the block is 99.1%. The contact angle of the test block with the wetting phase is 40 degrees, and the bacillus circulans is 5.0 multiplied by 10 in the formation water2One per ml. The method of the present invention is implemented in the block, and the specific steps are as follows:
(1) and (3) testing the screening of the oil reservoir, wherein the screening standard comprises that the oil phase wetting contact angle of the oil reservoir is less than 70 degrees and microorganisms for changing wettability exist in the oil reservoir.
The test reservoir E18Oil reservoir temperature is 75 ℃, crude oil ground viscosity is 985 mPa.s, formation water mineralization degree is 6785mg/L, and permeability is 1100 multiplied by 10-3μm2In the formation water, Bacillus circulans 5.0 x 10 exists2Piece/ml, phase wetting contact angle 40 °. The present invention may be practiced in compliance with the screening criteria of the present invention.
(2) And (3) primarily screening the activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of the wettability microorganism.
The specific steps of the primary screening of the activating agent are as follows: a100 mL Erlenmeyer flask was taken and added to 75mL test reservoir E18Adding an activating agent into the produced fluid (see table 7); then placing the mixture at 75 ℃ under the temperature of a test oil reservoir for culturing for 25 d; the bacterial concentration of the bacillus circulans in the culture solution is determined, the determination result is shown in table 7, and 2-3 groups of activator formulas with higher bacterial concentration are preliminarily screened according to the bacterial concentration.
TABLE 7 concentration of activated bacteria of different activators and sequencing results
As can be seen from Table 7, the concentrations of the activated activators formula I, formula II and formula V are higher and are all larger than 1.0X 108The amount per ml of the activator is calculated according to the formula I (carbon source: succinic acid 2.0%, nitrogen source: cottonseed meal 0.5%, phosphorus source: phosphorus)Dipotassium hydrogen acid 0.06%), formulation two (carbon source: lactic acid 1.0%, nitrogen source: 0.2% of rapeseed cake powder, and a phosphorus source: dipotassium phosphate 0.03%) and formulation five (carbon source: 3.0% of lactic acid, nitrogen source: 0.3% of peanut powder, a phosphorus source: potassium dihydrogen phosphate 0.08%).
(3) And (3) screening the activating agent, namely screening the activating agent on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of the wetting contact angle of the oil phase.
The specific steps of the activator screening are as follows: first, test reservoir E18Washing oil from the natural rock core to prepare a standard rock core with phi 25 multiplied by 100mm, measuring the initial oil phase wetting contact angle of the rock core, and injecting an activator formula for preliminary screening, and performing static culture for 8 d; then measuring the wetting contact angle of the oil phase after the treatment of the core activator, and the test result is shown in table 8; and finally, screening the activator corresponding to the rock core with the largest change degree of the wetting contact angle as the screened activator.
TABLE 8 wetting contact angle test results of rock oil phase before and after activation with different activators
As can be seen from Table 8, the wetting angles of the oil phases of the tested oil reservoir rocks are obviously changed from oil wetting to water wetting after the activation of the first, second and fifth formulas, wherein the largest change is that the wetting contact angle is changed to 67 degrees (carbon source: 2.0% of succinic acid, nitrogen source: 0.5% of cottonseed meal, phosphorus source: 0.06% of dipotassium hydrogen phosphate), and therefore the formula of the screened activator is the carbon source: succinic acid 2.0%, nitrogen source: 0.5% of cotton seed powder, and a phosphorus source: dipotassium phosphate 0.06%.
The wetting contact angle was measured by ellipsometry.
(4) And determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value.
The injection amount determination method comprises the following specific steps: first, test reservoir E18Of natural rockWashing oil from core, preparing standard core with diameter of 25X 100mm, measuring initial oil phase contact angle of core, vacuumizing core, and saturating oil reservoir E18The PV (pore volume) of the core is determined; saturation test reservoir E18Measuring the amount of saturated crude oil until the produced liquid contains 100% of oil, and calculating the original oil saturation of the rock core; performing primary water flooding until the water content of produced liquid is consistent with the current comprehensive water content of the test oil reservoir; secondly, injecting activating agents with different volume amounts (see table 9), and carrying out static culture for 20 d; finally, performing secondary water flooding until the water content of the produced liquid is 100%; measuring the oil phase wetting contact angle after core treatment and calculating the enhanced recovery value (see table 9); and finally, screening out the injection quantity of the activator corresponding to the rock core with the largest wetting contact angle change degree and the largest recovery rate improvement value as the field injection quantity.
TABLE 9 degree of wetting angle change and enhanced recovery for different amounts of activator oil phase injected
| Serial number | Amount of activator injected, PV | Degree of change of wetting angle ° | Increase the harvest rate% |
| 1 | 0.1 | 37 | 16.2 |
| 2 | 0.2 | 50 | 18.0 |
| 3 | 0.3 | 67 | 24.3 |
| 4 | 0.4 | 60 | 22.5 |
| 5 | 0.5 | 55 | 19.3 |
As can be seen from table 9, the oil phase wetting angle change degree and the yield increase value of the core are different according to the injection amount of the activator, and the oil phase wetting angle change degree and the yield increase value of the core are the largest when the injection amount of the activator is 0.3PV, and are 67 ° and 24.3%, respectively, so that the optimal injection amount of the activator in the field is selected to be 0.3 PV.
In the block E18Injecting activator 2.49 × 106m3The field injection speed of the activator is 8m3/h。
And (3) evaluating field test results: the block E18The comprehensive water content is reduced to 61.5% from 99.1% before implementation, the water content is reduced to 37.6%, and the cumulative oil increase is 0.423 multiplied by 10 by 6 months and 30 days by 20205t, improving the recovery ratio by 25.3%; the validity period is 8 years, the input-output ratio is 1:18.3, the field test effect is good, and the invention has wide popularization and application prospects.
Example 4
Summary of the test reservoirs: victory oil field certain block F21Oil reservoir temperature of 80 deg.c, crude oil ground viscosity of 1867mPa · s, formation water mineralization of 9765mg/L, permeability of 650X 10-3μm2Stratum pressure 11.7MPa, geological reserve 5.6X 104m3Pore volume 7.5X 106m3. Before the test, the comprehensive water content of the block is 98.5 percent. The contact angle of the block phase wetting is 43 degrees and the bacillus firmus is 1.0 multiplied by 103Per m. The method of the present invention is implemented in the block, and the specific steps are as follows:
(1) and (3) testing the screening of the oil reservoir, wherein the screening standard comprises that the oil phase wetting contact angle of the oil reservoir is less than 70 degrees and microorganisms for changing wettability exist in the oil reservoir.
The test reservoir F21Oil reservoir temperature of 80 ℃, crude oil ground viscosity of 1867mPa & s, formation water mineralization of 9765mg/L, and permeability of 650 x 10-3μm2Bacillus firmus 1.0X 103Piece/ml, phase wetting contact angle 43 deg.. The present invention may be practiced in compliance with the screening criteria of the present invention.
(2) And (3) primarily screening the activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of the wettability microorganism.
The specific steps of the primary screening of the activating agent are as follows: a100 mL Erlenmeyer flask was taken and 65mL of the test reservoir F was added21Adding an activating agent into the produced fluid (see table 10); then placing the mixture at the temperature of the oil reservoir to be tested and culturing the mixture for 20 days at 80 ℃; the bacterial concentration of the bacillus firmus in the culture solution is determined, the determination result is shown in table 10, and 2-3 groups of activator formulas with higher bacterial concentration are preliminarily screened according to the bacterial concentration.
TABLE 10 concentration of activated bacteria and ranking results for different activators
As can be seen from Table 10, the concentrations of the activated activator formula I and the activated activator formula III are higher and are both greater than 1.0X 108Per ml, therefore, activation of the preliminary screenThe formula of the agent comprises a first formula (carbon source: 2.0% of succinic acid, nitrogen source: 0.5% of cottonseed meal, phosphorus source: 0.06% of dipotassium hydrogen phosphate), and a third formula (carbon source: 4.0% of ethanol, nitrogen source: 0.6% of cottonseed meal, phosphorus source: 0.01% of monopotassium phosphate).
(3) And (3) screening the activating agent, namely screening the activating agent on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of the wetting contact angle of the oil phase.
The specific steps of the activator screening are as follows: first, test reservoir F21Washing oil from the natural rock core to prepare a standard rock core with phi 25 multiplied by 100mm, measuring the initial oil phase wetting contact angle of the rock core, and injecting an activating agent formula for preliminary screening, and performing static culture for 7 d; then measuring the wetting contact angle of the oil phase after the treatment of the core activator, and the test result is shown in a table 11; and finally, screening the activator corresponding to the rock core with the largest change degree of the wetting contact angle as the screened activator.
TABLE 11 wetting contact angle test results of the rock oil phase before and after activation with different activators
As can be seen from Table 2, the wetting angle of the oil phase of the oil reservoir rock tested after the activation of the formula I and the formula III is obviously changed from oil wetting to water wetting, wherein the largest change is that of the formula III (carbon source: 4.0% of ethanol, nitrogen source: 0.6% of cottonseed meal, phosphorus source: 0.01% of monopotassium phosphate), the wetting contact angle is changed to 78 degrees, and therefore, the formula of the screened activator is the carbon source: ethanol 4.0%, nitrogen source: 0.6% of cotton seed powder, phosphorus source: 0.01 percent of monopotassium phosphate.
The wetting contact angle was measured by the tangent method.
(4) And determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value.
The injection amount determination method comprises the following specific steps: first, the reservoir D is tested12Washing the natural rock core with oil to obtain the productForming a standard rock core with phi of 25 multiplied by 100mm, measuring the initial oil phase contact angle of the rock core, vacuumizing the rock core, and testing the oil reservoir F in a saturation mode21The PV (pore volume) of the core is determined; measuring the amount of saturated crude oil until the crude oil of the oil reservoir is saturated until the produced liquid contains 100% of oil, and calculating the original oil saturation of the core; performing primary water flooding until the water content of produced liquid is consistent with the current comprehensive water content of the test oil reservoir; secondly, injecting activating agents with different volume amounts (see table 12), and carrying out static culture for 25 d; finally, performing secondary water flooding until the water content of the produced liquid is 100%; measuring the oil phase wetting contact angle after core treatment and calculating the enhanced recovery value (see table 12); and finally, screening out the injection quantity of the activator corresponding to the rock core with the largest wetting contact angle change degree and the largest recovery rate improvement value as the field injection quantity.
TABLE 12 degree of wetting angle change and enhanced recovery values for different amounts of injected activator oil phase
| Serial number | Amount of activator injected, PV | Degree of change of wetting angle ° | Increase the harvest rate% |
| 1 | 0.1 | 24 | 13.2 |
| 2 | 0.2 | 43 | 15.3 |
| 3 | 0.3 | 52 | 21.5 |
| 4 | 0.4 | 65 | 27.7 |
| 5 | 0.5 | 56 | 23.1 |
As can be seen from table 12, the oil phase wetting angle change degree and the yield increase value of the core are different according to the injection amount of the activator, and the oil phase wetting angle change degree and the yield increase value of the core are respectively the largest when the injection amount of the activator is 0.4PV, and are respectively 65 ° and 27.7%, so that the optimal injection amount of the activator in the field is selected to be 0.3 PV.
In the block F21Injecting activator 3.0 × 106m3The field injection speed of the activator is 12m3/h。
And (3) evaluating field test results: the block F21The comprehensive water content is reduced to 63.2 percent from 98.5 percent before implementation, the water content is reduced to 35.3 percent, and the cumulative oil increase is 1.30 multiplied by 10 by 6 months and 30 days by 20204t, improving the recovery ratio by 23.2%; the validity period is 6.5 years, the input-output ratio is 1:16.3, the field test effect is good, and the invention has wide popularization and application prospects.
Example 5
Summary of the test reservoirs: victory oil field certain block F18Oil deposit temperature of 78 deg.c, ground viscosity of 1560 mPa.s, water mineralization of 7896mg/L, and permeability of 1250X 10-3μm2Ground, earthLamination pressure 15.3MPa, geological reserve 7.3X 104m3Pore volume 8.7X 106m3. Before the test, the comprehensive water content of the block is 99.3 percent. The contact angle of the test block phase wetting is 38 degrees, and the bacillus pumilus is 5.0 multiplied by 10 degrees in the formation water3One per ml. The method of the present invention is implemented in the block, and the specific steps are as follows:
(1) and (3) testing the screening of the oil reservoir, wherein the screening standard comprises that the oil phase wetting contact angle of the oil reservoir is less than 70 degrees and microorganisms for changing wettability exist in the oil reservoir.
The test reservoir F18Oil deposit temperature is 78 ℃, crude oil ground viscosity is 1560mPa & s, stratum water mineralization degree is 7896mg/L, and permeability is 1250 multiplied by 10-3μm2Bacillus pumilus 5.0 × 10 in the formation water3Piece/ml, phase wetting contact angle 38 deg.. The present invention may be practiced in compliance with the screening criteria of the present invention.
(2) And (3) primarily screening the activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of the wettability microorganism.
The specific steps of the primary screening of the activating agent are as follows: 100mL Erlenmeyer flask was taken and 80mL test reservoir F was added18Adding an activator into the produced fluid (see table 13); then placing the mixture at the temperature of a test oil reservoir and culturing the mixture for 30d at 78 ℃; the bacterial concentration of the bacillus pumilus in the culture solution is determined, the determination result is shown in table 13, and 2-3 groups of activator formulas with higher bacterial concentration are preliminarily screened according to the bacterial concentration.
TABLE 13 concentration of activated different activators and ranking results
As can be seen from Table 13, the concentrations of the activated bacteria of the activator formula III, the activator formula IV and the activator formula V are higher and are all larger than 1.0 multiplied by 108The amount per ml of the solution was determined so that the preliminarily screened formulations of the activators were formulation three (carbon source: ethanol 4.0% nitrogen source: cottonseed meal 0.6%, phosphorus source: monopotassium phosphate 0.01%), formulation four (carbon source: succinic acid 5.0%, nitrogen source: rapeseed meal 0.1%, phosphorus source: rapeseed meal 0.1%)Source: dipotassium phosphate 0.05%) and formulation five (carbon source: 3.0% of lactic acid, nitrogen source: 0.3% of peanut powder, a phosphorus source: potassium dihydrogen phosphate 0.08%).
(3) And (3) screening the activating agent, namely screening the activating agent on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of the wetting contact angle of the oil phase.
The specific steps of the activator screening are as follows: first, test reservoir F18Washing oil from the natural rock core to prepare a standard rock core with phi 25 multiplied by 100mm, measuring the initial oil phase wetting contact angle of the rock core, and injecting an activator formula for preliminary screening, and performing static culture for 10 d; then measuring the wetting contact angle of the oil phase after the treatment of the core activator, and the test result is shown in a table 14; and finally, screening the activator corresponding to the rock core with the largest change degree of the wetting contact angle as the screened activator.
TABLE 14 wetting contact angle test results of the rock oil phase before and after activation with different activators
As can be seen from Table 14, the wetting angles of the oil phases of the tested oil reservoir rocks are obviously changed from oil wetting to water wetting after the activation of the three, four and five formulas, wherein the largest change is that the wetting contact angle is changed to 72 degrees according to the three formula (carbon source: 4.0% of ethanol, nitrogen source: 0.6% of cottonseed meal and phosphorus source: 0.01% of monopotassium phosphate), and therefore, the formula of the screened activator is carbon source: ethanol 4.0 wt%, nitrogen source: 0.6 wt% of cotton seed powder, phosphorus source: potassium dihydrogen phosphate 0.01 wt%.
The wetting contact angle was measured by the Laplace-Young method.
(4) And determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value.
The injection amount determination method comprises the following specific steps: first, test reservoir F18Washing natural rock core with oil, making into standard rock core with diameter of 25X 100mm, and measuring initial oil of rock coreContact angle, then vacuuming the core, and testing the oil reservoir by saturation18The PV (pore volume) of the core is determined; measuring the amount of saturated crude oil until the crude oil of the oil reservoir is saturated until the produced liquid contains 100% of oil, and calculating the original oil saturation of the core; performing primary water flooding until the water content of produced liquid is consistent with the current comprehensive water content of the test oil reservoir; secondly, injecting activating agents with different volume amounts (see table 15), and carrying out static culture for 30 d; finally, performing secondary water flooding until the water content of the produced liquid is 100%; measuring the oil phase wetting contact angle after core treatment and calculating the enhanced recovery value (see table 15); and finally, screening out the injection quantity of the activator corresponding to the rock core with the largest wetting contact angle change degree and the largest recovery rate improvement value as the field injection quantity.
TABLE 15 degree of wetting angle change and enhanced recovery values for different amounts of injected activator oil phase
| Serial number | Amount of activator injected, PV | Degree of change of wetting angle ° | Increase the harvest rate% |
| 1 | 0.1 | 27 | 12.6 |
| 2 | 0.2 | 41 | 16.3 |
| 3 | 0.3 | 68 | 24.9 |
| 4 | 0.4 | 60 | 22.2 |
| 5 | 0.5 | 53 | 21.0 |
As can be seen from table 15, the oil phase wetting angle change degree and the yield increase value of the core are different according to the injection amount of the activator, and the oil phase wetting angle change degree and the yield increase value of the core are respectively the largest when the injection amount of the activator is 0.3PV, and are respectively 68 ° and 24.9%, so that the optimal injection amount of the activator in the field is selected to be 0.3 PV.
In the block F18Injecting activator 2.61X 105m3The field injection speed of the activator is 15m3/h。
And (3) evaluating field test results: the block F18The comprehensive water content is reduced to 63.2 percent from 99.3 percent before implementation, the water content is reduced to 36.1 percent, and the cumulative oil increase is 1.68 multiplied by 10 by 1.68 when the total water content is up to 2019, 12 months and 30 days4t, improving the recovery ratio by 23.0%; the validity period is 7.2 years, the input-output ratio is 1:17.3, the field test effect is good, and the invention has wide popularization and application prospects.
Claims (18)
1. A method for improving the recovery ratio of an oil reservoir by changing the wettability of the oil reservoir by using microorganisms, which comprises the following steps:
(1) screening a test oil reservoir, wherein the screening standard comprises that the wetting contact angle of the oil phase of the test oil reservoir is less than 70 degrees and microorganisms for changing wettability exist in the oil reservoir;
(2) the method comprises the following steps of (1) primarily screening an activating agent, wherein the primarily screening method is a static culture method, and the primary screening is based on changing the bacterial concentration of a wettability microorganism;
(3) screening an activator, namely screening the activator on the basis of primary screening, wherein the screening method adopts a physical simulation method and is based on the change degree of an oil phase wetting contact angle;
(4) and determining the field injection amount of the activator by adopting a physical simulation method according to the change degree of the oil phase wetting contact angle and the improvement of the recovery rate value.
2. The method of claim 1, wherein the criteria for screening the test reservoir further comprises: oil reservoir permeability less than or equal to 2000 x 10-3μm2The oil reservoir temperature is less than or equal to 90 ℃, the crude oil viscosity is less than or equal to 20000mPa.s, and the formation water mineralization is less than or equal to 150000 mg/L. More preferably, the oil reservoir permeability is less than or equal to 1000 multiplied by 10-3μm2The oil reservoir temperature is less than or equal to 70 ℃, the crude oil viscosity is less than or equal to 10000mPa.s, and the formation water mineralization is less than or equal to 50000 mg/L.
3. The method for improving the recovery efficiency of an oil reservoir by changing the wettability of the oil reservoir through the microorganisms according to claim 1, wherein the microorganisms for changing the wettability are one or more of bacillus natto, bacillus polymyxa, bacillus firmus, bacillus pumilus and bacillus circulans.
4. The method for enhancing recovery from an oil reservoir by altering wettability of the oil reservoir using a microorganism as set forth in claim 3, wherein said wettability-altering microorganism is Bacillus polymyxa or Bacillus circulans.
5. The method for improving the recovery efficiency of an oil reservoir by changing the wettability of the oil reservoir through microorganisms according to claim 1, wherein the specific steps of the primary screening of the activating agent are as follows: taking a 100mL conical flask, adding 60-80 mL of produced liquid of a test oil reservoir, and adding an activating agent; then placing the mixture at the temperature of the oil reservoir to be tested for culturing for 10-30 d; and (3) determining the bacterial concentration of the wettability-changing microorganisms in the culture solution, and primarily screening 2-3 groups of activating agent formulas with higher bacterial concentration according to the bacterial concentration.
6. The method for improving the recovery ratio of an oil reservoir by changing the wettability of the oil reservoir through the microorganisms according to claim 1 or 5, wherein the specific steps of the activator screening are as follows: firstly, washing oil from a natural rock core of a test oil reservoir to prepare a standard rock core with phi 25 multiplied by 100mm, measuring an initial oil phase wetting contact angle of the rock core, then injecting a preliminarily screened activating agent formula, and performing static culture for 5-10 days; then measuring an oil phase wetting contact angle after the core activator is treated; and finally, screening the activator corresponding to the rock core with the largest change degree of the wetting contact angle as the screened activator.
7. The method for improving recovery efficiency of an oil reservoir by changing the wettability of the oil reservoir through microorganisms according to claim 1, wherein the injection amount is determined by the following specific steps: firstly, washing oil from a natural core of a test oil reservoir to prepare a standard core with phi 25 multiplied by 100mm, measuring an initial oil phase contact angle of the core, vacuumizing the core, saturating formation water of the test oil reservoir, and measuring PV (pore volume) of the core; measuring the amount of saturated crude oil until the crude oil of the oil reservoir is saturated until the produced liquid contains 100% of oil, and calculating the original oil saturation of the core; performing primary water flooding until the water content of produced liquid is consistent with the current comprehensive water content of the test oil reservoir; secondly, injecting activating agents with different volume amounts, and performing static culture for 10-30 d; finally, performing secondary water flooding until the water content of the produced liquid is 100%; measuring the oil phase wetting contact angle after the rock core is treated and calculating the improved recovery value; and finally, screening out the injection quantity of the activator corresponding to the rock core with the largest wetting contact angle change degree and the largest recovery rate improvement value as the field injection quantity.
8. The method of claim 1, wherein the wetting contact angle measurement is one of tangent, circle, ellipse, and Laplace-Young.
9. The method of claim 8, wherein the wetting contact angle is measured by a tangent method or a circle method.
10. The method for enhancing recovery of a reservoir by altering wettability of the reservoir using microorganisms of claim 1, wherein the method further comprises field testing and effect evaluation.
11. The method of claim 10, wherein the field testing comprises continuously injecting the activator from a water injection well of the reservoir being tested using a high pressure plunger pump.
12. The method of claim 10, wherein the evaluation criteria are expiration date, enhanced oil recovery degree, and input-output ratio.
13. The method of claim 1, wherein the activator comprises a carbon source, a nitrogen source, and a phosphorus source at a concentration of 1.0-5.0%, 0.1-0.6%, and 0.01-0.08% by weight, respectively.
14. The method of claim 13, wherein the carbon source is one of succinic acid, lactic acid, and ethanol.
15. The method for improving recovery efficiency of an oil reservoir by changing wettability of the oil reservoir using microorganisms according to claim 13, wherein the nitrogen source is one of cottonseed meal, rapeseed meal and peanut meal.
16. The method for enhancing recovery in a reservoir by altering the wettability of the reservoir using a microorganism as set forth in claim 13, wherein said source of phosphorus is dipotassium hydrogen phosphate or potassium dihydrogen phosphate.
17. The method for enhanced oil recovery using microorganisms for altering the wettability of an oil reservoir according to claim 1, wherein the field injection amount of the activator is 0.1-0.5 PV.
18. The method for enhanced oil recovery using microorganisms for altering the wettability of an oil reservoir according to claim 1, wherein the activator injection rate in situ is 5-15m3/h。
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