CN110566170A - Method for improving heterogeneity of oil reservoir by inducing mineral precipitation through microorganisms in oil reservoir - Google Patents
Method for improving heterogeneity of oil reservoir by inducing mineral precipitation through microorganisms in oil reservoir Download PDFInfo
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK 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 OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
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- Geophysics (AREA)
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Abstract
The invention belongs to the technical field of oil and gas field development, and particularly relates to a method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation through microorganisms in the oil reservoir, which specifically comprises the following steps: screening test blocks; testing the abundance of carbonate mineralized bacteria in the reservoir formation water; determining a microbial oil displacement mode of an oil reservoir; screening exogenous microorganisms or activators; determining an in-situ implantation process; field test and evaluation of effect. The invention has wide application range of oil reservoirs, is suitable for both the oil reservoir with medium and high permeability and the high-temperature and high-salinity oil reservoir; meanwhile, the method can effectively improve the heterogeneity degree of the oil deposit, prolong the validity period and improve the recovery ratio, the improvement rate of the heterogeneity degree exceeds 70%, the validity period reaches more than 3 years, and the recovery ratio is improved by more than 15%, so that the method is favorable for field popularization and application.
Description
Technical Field
The invention belongs to the field of water plugging of oil-water wells, and particularly relates to a method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation through microorganisms in the oil reservoir.
background
In the process of petroleum reservoir formation, due to variation of a hydrocarbon source organic phase and maturity of filled petroleum and existence of barriers such as an upper interlayer and a fault of an internal structure of a petroleum reservoir, the difference of porosity and permeability of the reservoir exists, the difference mainly shows the vertical and plane heterogeneity of the petroleum reservoir, and the influence on the development effect of the petroleum reservoir, particularly the development of a heavy oil reservoir is large. Reservoir heterogeneity from the point of development, the direction of fluid seepage is mainly affected, and the direction of water injection propulsion and the swept system are affected; for an oil well, the heterogeneity of the oil reservoir will affect the direction of its effect, the yield after the effect, etc.
At present, methods for improving heterogeneous oil reservoirs mainly comprise polymers, gel systems, microspheres and the like. Although these techniques can achieve their functions well, they all have certain limitations. After the gel system is gelled, the viscosity is high, the injection is difficult, the stratum migration capacity is weak, the conventional profile control radius is small, and the effective period is short; the heterogeneity improvement of polymers and microspheres is relatively limited, and the construction process and the popularization of field conditions have certain limitations.
CN103421475A reports an oil well deep composite plugging profile control agent and an application thereof, wherein the composite plugging profile control agent comprises the following components: gel plugging agent solution, particle plugging agent and surfactant. Compared with the application, the composite plugging profile control agent disclosed by the invention realizes plugging profile control in the deep part of an oil layer of an oil well through Jamin effect of foam generated in the deep part of a stratum and physical plugging effect of a solid-phase plugging agent. However, the technology still acts on the internal pore channels of the oil reservoir from the external environment, has no autonomous selectivity, completely depends on the characteristics of the oil reservoir to realize the improvement of heterogeneity, and has poor targeted plugging effect.
CN 109457688A discloses a coarse-grained soil reinforcing method based on microorganism-induced calcium carbonate deposition, which comprises the steps of adding viscous bacteria solution into a coarse-grained soil sample for bacteria fixation; adding a treating fluid containing urea and calcium ions to perform cementation treatment on the coarse-grained soil subjected to bacterial immobilization. The invention applies the MICP technology to coarse-grained soil with large grain diameter and large pore for the first time, improves the mechanical property of the coarse-grained soil and keeps good water permeability. The invention applies the process of microbial induced bioprecipitation to the field of civil engineering, and does not relate to the technical application of oil reservoir in the aspect of improving the recovery ratio.
CN104502524A discloses a screening method of an endogenous microorganism activator with a profile control function. The method specifically comprises the following steps: firstly, screening an endogenous activator carbon source aiming at a specific oil reservoir; secondly, screening a phosphorus source and a nitrogen source of the activator, evaluating the injection capability of the activator, optimizing the concentration and the injection amount of the activator and evaluating the oil displacement effect of the activator to screen the activator; and finally, carrying out field test and effect tracking according to the screened activating agent. The invention only realizes the effect of improving the heterogeneity by utilizing biomacromolecule substances metabolized by organisms in the oil reservoir, the strength of the substances is weak, and the oil reservoir heterogeneity is difficult to be thoroughly improved in the oil reservoir with large water body strength.
CN 106479470A discloses a low-tension foam agent for improving the crude oil recovery ratio of an inhomogeneous reservoir and an oil displacement method, wherein the low-tension foam agent for improving the crude oil recovery ratio of the inhomogeneous reservoir comprises the following raw materials in percentage by weight: 40-60 parts of main agent, 3-15 parts of foam stabilizer, 8-15 parts of alkyl betaine, 0.1-3 parts of methyl cellulose and the balance of urban tap water. The oil displacement method comprises the following steps: a. firstly, adding water into a low-tension foaming agent to prepare an aqueous solution, and then injecting the aqueous solution into a water injection well to be used as a front-mounted slug; b. and (b) adding water into the low-tension foaming agent to prepare an aqueous solution, mixing the aqueous solution with nitrogen, air or natural gas, and injecting the mixture into the water injection well of the low-tension foam flooding in the step (a), wherein the injection amount is 0.2-0.4 times of that of the formation pore body, so as to form a foam flooding fluid and perform low-tension foam flooding. Compared with the method, the temporary plugging of the heterogeneous oil deposit is realized only through the formed low-interface foam flooding fluid, the technology can only realize the effective plugging effect within a period of time, periodic measures are required, and the essential improvement of the oil deposit cannot be realized.
Disclosure of Invention
The invention aims to overcome the defects of the prior art and provide a method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation through microorganisms in the oil reservoir.
The invention discloses a method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation by microorganisms in the oil reservoir, which is characterized by comprising the following steps:
(1) screening of test blocks
The screening of the test block needs to satisfy the following conditions: the oil deposit temperature is less than 90 ℃, and the stratum permeability is more than 1000 multiplied by 10-3μm2The viscosity of the crude oil is less than 50000mPa.s and the degree of mineralization is less than 150000mg/L when the viscosity is less than 2000 mPa.s; the formation water contains calcium ions or magnesium ions, the concentration of the calcium ions and the magnesium ions is less than or equal to 200mg/L, and carbonate mineralization bacteria with biological induction function exist in the formation water.
(2) Test of abundance of carbonate mineralized bacteria in reservoir formation water
The method for testing the abundance of carbonate mineralized bacteria in the reservoir formation water comprises the following specific steps:
Firstly, 10L of oil-water sample collected by an oil reservoir needs to be emptied by 5-10L of liquid in a ground pipeline before sampling, so that microbial pollution in the pipeline is avoided;
Secondly, sample pretreatment: conveying the obtained stratum water sample to a room within 3h, firstly carrying out petroleum ether pretreatment on the sample, and centrifugally collecting thalli;
extraction of DNA and PCR reaction: extracting the genome of the collected thalli by using a genome extraction kit, and amplifying a 16SV4 region in a sample DNA template by PCR reaction;
Fourthly, high-throughput sequencing and community structure analysis of samples: the high-throughput sequencing of the sample adopts an Illumina sequencing method; and after sequencing is completed, performing bioinformatics analysis to obtain the abundance of the carbonate mineralization bacteria in the oil reservoir water sample.
(3) Determination of microbial oil displacement mode of oil reservoir
determining an oil displacement mode according to the abundance of carbonate mineralized bacteria in the oil reservoir formation water, and if the abundance of the carbonate mineralized bacteria is less than 1%, adopting an exogenous microorganism oil displacement mode; if the abundance of the carbonate mineralized bacteria is more than or equal to 1 percent, an endogenous microbial oil displacement mode is adopted.
(4) Screening for exogenous microorganisms or activators
If an exogenous microorganism oil displacement mode is adopted, exogenous microorganism screening is required, and the specific method comprises the following steps: adding 100ml of formation water and 2-5ml of exogenous microorganism and a nutrition system into a triangular flask with the volume of 250ml, and then adding quartz sand with the composition consistent with that of reservoir sand bodies of an oil reservoir; and (3) placing the triangular flask at the oil reservoir temperature, culturing for 20-30d, and screening out exogenous microorganisms with the pH value of more than 7 or the sand body at the bottom of the triangular flask converted from a loose state to a cemented state and the cemented sand body tolerance pressure of more than or equal to 15MPa in the system.
The exogenous microorganism is carbonate mineralization bacteria which has an enzymatic action with an oil reservoir environment, and specifically is one or more of bacillus pasteurii, bacillus geotrichum and bacillus subtilis.
The nutrient system comprises 10-20 g/L of carbon source and 5-10 g/L, NaCl 5-10 g/L of nitrogen source, wherein the carbon source is one of corn steep liquor hydrolysate, glucose and sucrose, and the nitrogen source is one of urea, beef extract, peptone and ammonium chloride.
If an endogenous microbial oil displacement mode is adopted, screening of an activator is required, and the specific method is as follows: adding 100ml of formation water and 2-5ml of activating agent into a triangular flask with the volume of 250ml, then adding quartz sand consistent with the composition of reservoir sand bodies of an oil reservoir, placing the triangular flask at the temperature of the oil reservoir, culturing for 15-20 days, and screening out the activating agent with the pH value of more than 7 or the activating agent with the capability of converting the sand bodies at the bottom of the triangular flask from a loose state into a cemented state and the cemented sand bodies with the tolerance pressure of more than or equal to 15 MPa.
The activating agent comprises 0.3-0.5 wt% of carbon source, 0.3-0.5 wt% of nitrogen source, 0.5-1 wt% of calcium ion, 0.5-1 wt% of sodium carbonate and 0.03-0.05 wt% of biological polysaccharide, wherein the carbon source is one of glucose, sucrose, starch, molasses and whey, the nitrogen source is one of beef extract, peptone, peanut cake powder and amino acid, and the biological polysaccharide is one of polysaccharide, heteropolysaccharide and glycoconjugate.
The viscosity of the activator is 20-50 mPa.s.
(5) in-situ implant process determination
The determination of the in-situ implantation process comprises the following specific steps: filling two groups of sand-filled rock cores, wherein the range of the rock core group is consistent with the range of the test block; secondly, respectively vacuumizing the formation water of the saturated test block of the two groups of rock cores, and calculating the pore volume; placing the two groups of cores at the oil reservoir temperature of the test block to saturate the crude oil of the test block, and aging the cores for 7 d; connecting the two groups of rock cores in parallel and carrying out primary water flooding at the speed of 1.0-1.5 ml/min until the water content of produced liquid is consistent with the comprehensive water content of the test block, and simultaneously measuring the water phase permeability k of the two groups of rock cores when the water content of the produced liquid is consistent with the comprehensive water content of the test blockLow 1And kHeight 1(ii) a Injecting the screened exogenous microorganisms or the activators into the rock core group in different injection modes, culturing for 15-30 d, and testing the water phase permeability k of the two rock cores respectivelyLow 2And kheight 2(ii) a Screening out low permeability core plugging rate etaIs low inLess than or equal to 2 percent and high-permeability core plugging rate etaHeight ofthe injection mode of more than or equal to 50 percent is the best field injection process.
The injection mode comprises a segmented plug type injection and a continuous type injection.
The calculation formula of the core plugging rate eta is as follows:
Wherein: k is a radical of1Initial determination of the core Water permeability, 10-3μm2；
k2After the cultivation the water phase permeability of the core, 10-3μm2。
(6) On-site test and evaluation of Effect
And injecting exogenous microorganisms or an activating agent from the water injection well of the test block by using a high-pressure plunger pump according to the field injection process determined by the steps, and simultaneously evaluating the field test effect, wherein the evaluation indexes comprise the recovery efficiency improvement, the heterogeneity improvement degree and the validity period.
Compared with the prior art, the invention has the following advantages and beneficial effects:
(1) The invention has wide application range of oil reservoirs, is suitable for both the oil reservoir with medium and high permeability and the high-temperature and high-salinity oil reservoir;
(2) According to the invention, by utilizing the continuous enzymatic action between carbonate mineralized bacteria (exogenous or endogenous) and surrounding media, a cementing substance with higher tolerance pressure is formed, so that large pore channels of a high-permeability region of an oil reservoir are effectively reduced or blocked, the heterogeneity degree of the oil reservoir is improved, and the aim of improving the recovery ratio of the oil reservoir is fulfilled;
(3) The activator or nutrient has certain viscosity, and the swept volume of the activator or carbonate mineralized bacteria can be effectively increased, so that the oil reservoir heterogeneity can be further improved.
(4) The invention can effectively improve the heterogeneity degree of the oil deposit, prolong the validity period and improve the recovery ratio, the improvement rate of the heterogeneity degree exceeds 70%, the validity period reaches more than 3 years, and the recovery ratio reaches more than 15%, thereby being beneficial to the field popularization and application.
Detailed Description
The technical solution of the present invention is further described with reference to the following specific examples.
Example 1
Victory oil field certain block J10Oil reservoir temperature of 46 ℃, porosity of 36 percent and average permeability of 2500 multiplied by 10-3μm2The minimum and maximum permeability values are 2000 x 10-3μm2、6000×10-3μm2The extreme difference is 3, the heterogeneity is severe, the crude oil viscosity is 3100mPa & s, and the mineralization degree is 4712 mg/L. The block before the test contains 97 percent of water, the daily oil yield is 1.5t/d, and the daily liquid yield is 50m3And d. The block has high crude oil viscosity and serious water channeling phenomenon, and is the main reason for low oil well productivity of the block. The ion composition and the content of carbonate mineralized bacteria in the output liquid of the block are measured, and the test results are shown in table 1. Using the method of the present invention to block J10Implementing microorganisms improves heterogeneity in situ and increases yield of the block.
TABLE 1 Block J10Test results of effluent properties
(1) Screening of test blocks
The oil reservoir temperature of the test block is 46 ℃, and the average permeability is 2500 multiplied by 10-3μm2The crude oil viscosity is 3100 mPas, the mineralization degree is 4712mg/L, the concentration of calcium ions in formation water is 180.44mg/L, the concentration of magnesium ions is 31.96mg/L, and carbonate mineralization bacteria exist. The present invention may be implemented to meet the block screening criteria of the present invention.
(2) Test of abundance of carbonate mineralized bacteria in reservoir formation water
To J10The method for testing the abundance of carbonate mineralized bacteria in the water of the block stratum comprises the following specific steps:
Firstly, 10L of oil-water sample collected by an oil reservoir needs to be emptied of 5L of liquid in a ground pipeline before sampling, so that microbial pollution in the pipeline is avoided;
secondly, sample pretreatment: conveying the obtained stratum water sample to a room within 3h, firstly carrying out petroleum ether pretreatment on the sample, and centrifugally collecting thalli;
extraction of DNA and PCR reaction: extracting the genome of the collected thalli by using a genome extraction kit, and amplifying a 16SV4 region in a sample DNA template by PCR reaction;
Fourthly, high-throughput sequencing and community structure analysis of samples: the high-throughput sequencing of the sample adopts an Illumina sequencing method; and after sequencing is completed, performing bioinformatics analysis to obtain that the abundance of the carbonate mineralization bacteria in the oil reservoir water sample is 12%.
(3) Determination of microbial oil displacement mode of oil reservoir
J10The abundance of the carbonate mineralized bacteria in the oil reservoir water sample is 12%, so that the test block adopts an endogenous microbial oil displacement mode.
(4) Screening for activators
adding 100ml of formation water and 2ml of activating agent into a triangular flask with the volume of 250ml, then adding quartz sand which is consistent with the composition of reservoir sand bodies of an oil reservoir, placing the triangular flask at the temperature of 46 ℃ of the oil reservoir, culturing for 15d, wherein the experimental result is shown in table 2, and screening out the activating agent with the pH value of more than 7 or the activating agent with the capability of converting the sand bodies at the bottom of the triangular flask from a loose state into a cemented state and the cemented sand bodies with the tolerance pressure of more than or equal to 15 MPa.
TABLE 2 Block J10Experimental results for activators
As can be seen from table 2: the sand body state, the tolerance pressure and the pH value of the formula 3 are respectively a cementation state, 17MPa and 9, and the screening requirement is met. Thus, the activators screened were: 0.5 wt% of starch, 0.3 wt% of amino acid, 1.0 wt% of calcium chloride, 0.8 wt% of sodium carbonate and 0.05 wt% of polysaccharide.
(5) In-situ implant process determination
The determination of the in-situ implantation process comprises the following specific steps: the filling permeability is 2000X 10-3、6000×10-3μm2Sand-filled coretwo groups, with the range of 3; secondly, respectively vacuumizing the formation water of the saturated test block of the two groups of rock cores, and calculating the pore volume; placing the two groups of cores at the oil reservoir temperature of the test block to saturate the crude oil of the test block, and aging the cores for 7 d; connecting the two groups of rock cores in parallel and carrying out primary water flooding at the speed of 1.0ml/min until the water content of produced liquid is consistent with the comprehensive water content of the test block, and simultaneously measuring the water phase permeability k of the two groups of rock cores when the water content of the produced liquid is consistent with the comprehensive water content of the test blocklow 1And kHeight 1(ii) a Injecting the selected activators (starch 0.5 wt%, amino acid 0.3 wt%, calcium chloride 1.0 wt%, sodium carbonate 0.8 wt%, and polysaccharide 0.05 wt%) into the core group by adopting a slug type injection and continuous injection mode, culturing for 15d, and testing the water phase permeability k of the two groups of cores respectivelylow 2And kHeight 2According to the method disclosed by the invention, the plugging rate eta of the screened rock core is calculated, and the result is shown in a table 3.
The calculation formula of the core plugging rate eta is as follows:
Wherein: k is a radical of1Initial determination of the core Water permeability, 10-3μm2；
k2After the cultivation the water phase permeability of the core, 10-3μm2。
table 3 core plugging rate test results for different injection modes
As can be seen from table 3, the slug type injection pattern meets the requirements, and therefore, the in-situ injection pattern of the activator is the slug type injection.
(6) On-site test and evaluation of Effect
The activator (0.5 wt% starch, 0.3 wt% amino acid, 1.0 wt% calcium chloride, 0.8 wt% sodium carbonate, 0.05 wt% polysaccharide) was injected from test block J using a high pressure plunger pump in situ as determined by the procedure described above (slug injection)10The water injection well is injected, and meanwhile, the evaluation of the field test effect is carried out, and the evaluation indexes comprise the recovery rate improvement, the heterogeneity improvement degree and the validity period.
The field test results are as follows: test Block J10The water content of the oil reservoir is obviously reduced, the water content is reduced to 81.5 percent from 97 percent, the water content is reduced by 15.5 percent, the daily oil is increased to 21.3t/d from 1.5t/d, the effective period reaches 4.5 years, the recovery ratio is improved by 17.6 percent, and the improvement rate of the heterogeneity degree is 78.5 percent.
Example 2
Victory oil field certain block G7Oil reservoir temperature of 66 ℃, porosity of 32 percent and average permeability of 3500 x 10-3μm2Permeability range 1000X 10-3～5000×10-3μm2The range is 5, and the heterogeneity is severe. The viscosity of crude oil is 6176 mPas, and the degree of mineralization is 7708 mg/L. The block before the test contains 97.3 percent of water, 0.9t/d of daily oil and 33m of daily liquid3And d. The block has high crude oil viscosity, strong heterogeneity and serious water channeling phenomenon, and is the main reason for low oil well productivity of the block. The ion composition and the content of carbonate mineralized bacteria in the output liquid of the block are measured, and the test results are shown in table 4. Using the method of the present invention to block G7implementing microorganisms improves heterogeneity in situ and increases yield of the block.
TABLE 4 Block G7Test results of effluent properties
(1) Screening of test blocks
The oil reservoir temperature of the test block is 66 ℃, and the average permeability is 3500X 10-3μm2Crude oil viscosity 6176 mPas, degree of mineralization 7708 mg/L. The concentration of calcium ions in the formation water is 138.44mg/L, the concentration of magnesium ions is 41.96mg/L,And carbonate mineralization bacteria are present. The present invention may be implemented to meet the block screening criteria of the present invention.
(2) Test of abundance of carbonate mineralized bacteria in reservoir formation water
For block G7The method for testing the abundance of carbonate mineralized bacteria in the formation water comprises the following specific steps:
Firstly, 10L of oil and water sample collected by an oil reservoir needs to be emptied of liquid 10L in a ground pipeline before sampling, so that microbial pollution in the pipeline is avoided;
Secondly, sample pretreatment: conveying the obtained stratum water sample to a room within 3h, firstly carrying out petroleum ether pretreatment on the sample, and centrifugally collecting thalli;
Extraction of DNA and PCR reaction: extracting the genome of the collected thalli by using a genome extraction kit, and amplifying a 16SV4 region in a sample DNA template by PCR reaction;
Fourthly, high-throughput sequencing and community structure analysis of samples: the high-throughput sequencing of the sample adopts an Illumina sequencing method; and after sequencing is completed, performing bioinformatics analysis to obtain that the abundance of the carbonate mineralization bacteria in the oil reservoir water sample is 0.7%.
(3) determination of microbial oil displacement mode of oil reservoir
G7The abundance of the carbonate mineralized bacteria in the oil reservoir water sample is 0.7%, so that the test block adopts an exogenous microorganism oil displacement mode.
(4) Screening of exogenous microorganisms
Adding 100ml of formation water and 5ml of exogenous microorganism and a nutrition system into a triangular flask with the volume of 250ml, and then adding quartz sand with the composition consistent with that of oil reservoir sand bodies; and (3) placing the triangular flask at the oil reservoir temperature of 66 ℃, culturing for 30d, wherein the test result is shown in table 5, and screening out exogenous microorganisms with the pH value of more than 7 or the sand body at the bottom of the triangular flask converted from a loose state to a cemented state, wherein the cemented sand body has the tolerance pressure of more than or equal to 15 MPa.
TABLE 5 Block G7Experimental results for exogenous microorganisms
As can be seen from table 5: the sand body state, the withstand pressure and the pH value of the formula 1 are respectively a cementation state, 16MPa and 9, and the screening requirement is met. Therefore, the screened exogenous microorganism is bacillus pasteurii, and the nutrient system comprises 10 wt% of corn steep liquor hydrolysate, 5 wt% of urea and 5 wt% of NaCl.
(5) In-situ implant process determination
the determination of the in-situ implantation process comprises the following specific steps: the filling permeability is 1000X 10-3、5000×10-3μm2Two groups of sand-filled rock cores with the range of 5; secondly, respectively vacuumizing the formation water of the saturated test block of the two groups of rock cores, and calculating the pore volume; placing the two groups of cores at the oil reservoir temperature of the test block to saturate the crude oil of the test block, and aging the cores for 7 d; connecting the two groups of rock cores in parallel and carrying out primary water flooding at the speed of 1.5ml/min until the water content of produced liquid is consistent with the comprehensive water content of the test block, and simultaneously measuring the water phase permeability k of the two groups of rock cores when the water content of the produced liquid is consistent with the comprehensive water content of the test blocklow 1And kHeight 1(ii) a Injecting the screened exogenous microorganisms (Bacillus pasteurii) and a nutrient system (corn steep liquor hydrolysate 10 wt%, urea 5 wt% and NaCl 5 wt%) into the core group by adopting a slug type injection and continuous injection mode, culturing for 20d, and then respectively testing the water phase permeability k of the two groups of cores againLow 2And kHeight 2according to the method disclosed by the invention, the plugging rate eta of the screened rock core is calculated, and the obtained data is shown in a table 6.
The calculation formula of the core plugging rate eta is as follows:
Wherein: k is a radical of1Initial determination of the core Water permeability, 10-3μm2；
k2After the cultivation the water phase permeability of the core, 10-3μm2。
Table 6 core plugging rate test results for different injection modes
as can be seen from table 6, the continuous injection mode satisfied the requirements, and therefore, the in-situ injection mode of the exogenous microorganisms and their nutrient system was continuous injection.
(6) On-site test and evaluation of Effect
Exogenous microorganisms (Bacillus pasteurii) and nutrient systems (corn steep liquor hydrolysate 10 wt%, urea 5 wt%, NaCl 5 wt%) were injected from test block G using a high pressure plunger pump in situ (continuous injection) as determined in the above procedure7The water injection well is injected, and meanwhile, the evaluation of the field test effect is carried out, and the evaluation indexes comprise the recovery rate improvement, the heterogeneity improvement degree and the validity period.
The field test results are as follows: test Block G7The water content of the oil reservoir is obviously reduced, the water content is reduced to 75.0 percent from 97.3 percent, the water content is reduced by 22.3 percent, the daily oil is increased to 28.6t/d from 0.9t/d, the validity period reaches 5 years, the recovery ratio is increased to 22.5 percent, the improvement rate of the heterogeneity degree is 82.7 percent, and the field test effect is good.
example 3
Victory oil field certain block CH4Oil reservoir temperature 70 deg.C, porosity 32.2%, average permeability 4000X 10-3μm2Permeability range 1500 × 10-3～6000×10-3μm2The extreme difference is 4, the viscosity of the crude oil is 4176mPa & s, and the mineralization degree is 10708 mg/L. The block before the test contains 98.0% of water, 1.1t/d of daily oil and 55m of daily liquid3And d. The block has high crude oil viscosity, strong heterogeneity and serious water channeling phenomenon, and is the main reason for low oil well productivity of the block. The ion composition and the content of carbonate mineralized bacteria in the output liquid of the block are measured, and the test results are shown in table 7. Using the method of the present invention to process block CH4The microorganism is implemented to improve the heterogeneity technology application in situ and improve the productivity of the block.
TABLE 7 Block CH4Test results of effluent properties
(1) Screening of test blocks
test Block CH4oil reservoir temperature of 70 ℃, porosity of 32.3 percent and average permeability of 4000 multiplied by 10-3μm2Crude oil viscosity 4176 mPas, degree of mineralization 10708 mg/L. The concentration of calcium ions in the formation water is 198.27mg/L, the concentration of magnesium ions is 11.36mg/L, and carbonate mineralized bacteria exist. The present invention may be implemented to meet the block screening criteria of the present invention.
(2) Test of abundance of carbonate mineralized bacteria in reservoir formation water
To CH4The method for testing the abundance of carbonate mineralized bacteria in the water of the block stratum comprises the following specific steps:
Firstly, 10L of oil-water sample collected by an oil reservoir needs to be emptied of 8L of liquid in a ground pipeline before sampling, so that microbial pollution in the pipeline is avoided;
Secondly, sample pretreatment: conveying the obtained stratum water sample to a room within 3h, firstly carrying out petroleum ether pretreatment on the sample, and centrifugally collecting thalli;
extraction of DNA and PCR reaction: extracting the genome of the collected thalli by using a genome extraction kit, and amplifying a 16SV4 region in a sample DNA template by PCR reaction;
Fourthly, high-throughput sequencing and community structure analysis of samples: the high-throughput sequencing of the sample adopts an Illumina sequencing method; and after sequencing is completed, performing bioinformatics analysis to obtain that the abundance of the carbonate mineralization bacteria in the oil reservoir water sample is 11%.
(3) Determination of microbial oil displacement mode of oil reservoir
CH4The abundance of the carbonate mineralized bacteria in the oil reservoir water sample is 11%, so that the test block adopts an endogenous microbial oil displacement mode.
(4) Screening for activators
Adding 100ml of formation water and 5ml of activating agent into a triangular flask with the volume of 250ml, then adding quartz sand which is consistent with the composition of reservoir sand bodies of an oil reservoir, placing the triangular flask at the temperature of 70 ℃ of the oil reservoir, culturing for 20 days, and screening out the activating agent with the pH value of more than 7 or the activating agent with the capability of converting the sand bodies at the bottom of the triangular flask from a loose state into a cemented state and the pressure resistance of the cemented sand bodies of more than or equal to 15MPa from the experimental result shown in Table 8.
Table 8 block CH4experimental results for activators
as can be seen from table 8: the sand body state, the tolerance pressure and the pH value of the formula 5 are respectively a cementation state, 16MPa and 9, and the screening requirement is met. Therefore, the selected activators were molasses 0.4 wt%, peptone 0.4 wt%, calcium chloride 1.0 wt%, sodium carbonate 0.7 wt%, and heteropolysaccharide 0.03 wt%.
(5) In-situ implant process determination
the determination of the in-situ implantation process comprises the following specific steps: the filling permeability is 1500 multiplied by 10 respectively-3μm2、6000×10-3μm2Two groups of sand-filled rock cores with the range of 4; secondly, respectively vacuumizing the formation water of the saturated test block of the two groups of rock cores, and calculating the pore volume; placing the two groups of cores at the oil reservoir temperature of the test block to saturate the crude oil of the test block, and aging the cores for 7 d; connecting the two groups of rock cores in parallel and carrying out primary water flooding at the speed of 1.2ml/min until the water content of produced liquid is consistent with the comprehensive water content of the test block, and simultaneously measuring the water phase permeability k of the two groups of rock cores when the water content of the produced liquid is consistent with the comprehensive water content of the test blockLow 1And kHeight 1(ii) a Injecting the selected activator system (molasses 0.4 wt%, peptone 0.4 wt%, calcium chloride 1.0 wt%, sodium carbonate 0.7 wt%, and heteropolysaccharide 0.03 wt%) into the core group by adopting a segmental injection and continuous injection manner, culturing for 30d, and testing the water phase permeability k of the two groups of cores respectivelylow 2And kheight 2According to the method disclosed by the invention, the plugging rate eta of the screened rock core is calculated, and the obtained data is shown in a table 9.
The calculation formula of the core plugging rate eta is as follows:
Wherein: k is a radical of1Initial determination of the core Water permeability, 10-3μm2；
k2After the cultivation the water phase permeability of the core, 10-3μm2。
Table 9 core plugging rate test results for different injection modes
As can be seen from table 9, the continuous injection method satisfies the requirements, and therefore, the in-situ injection method of the activator is a continuous injection method.
(6) On-site test and evaluation of Effect
The activators (molasses 0.4 wt%, peptone 0.4 wt%, calcium chloride 1.0 wt%, sodium carbonate 0.7 wt%, heteropolysaccharide 0.03 wt%) were injected from the test block CH in situ (continuous injection) using a high-pressure plunger pump according to the above-described procedure4The water injection well is injected, and meanwhile, the evaluation of the field test effect is carried out, and the evaluation indexes comprise the recovery rate improvement, the heterogeneity improvement degree and the validity period.
The field test results are as follows: test Block CH4The water content of the oil reservoir is obviously reduced, the water content is reduced to 80.2 percent from 98.0 percent, the water content is reduced by 17.8 percent, the daily oil is increased to 25.6t/d from 1.1t/d, the validity period reaches 4 years, the recovery ratio is improved by 18.0 percent, the improvement rate of the heterogeneity degree is 80.2 percent, and the field test effect is good.
Claims (14)
1. A method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation by microorganisms in the oil reservoir is characterized by comprising the following steps:
(1) Screening test blocks;
(2) Testing the abundance of carbonate mineralized bacteria in the reservoir formation water;
(3) Determining a microbial oil displacement mode of an oil reservoir;
(4) Screening exogenous microorganisms or activators;
(5) Determining an in-situ implantation process;
(6) Field test and evaluation of effect.
2. The method of claim 1, wherein the screening of the test blocks is performed under conditions that: the oil deposit temperature is less than 90 ℃, and the stratum permeability is more than 1000 multiplied by 10-3μm2the viscosity of the crude oil is less than 50000mPa.s and the degree of mineralization is less than 150000mg/L when the viscosity is less than 2000 mPa.s; the formation water contains calcium ions or magnesium ions, the concentration of the calcium ions and the magnesium ions is less than or equal to 200mg/L, and carbonate mineralization bacteria with biological induction function exist in the formation water.
3. The method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation through microorganisms in the oil reservoir according to claim 1, wherein the method for testing the abundance of carbonate mineralized bacteria in the formation water of the oil reservoir comprises the following specific steps:
Firstly, 10L of oil-water sample collected by an oil reservoir needs to be emptied by 5-10L of liquid in a ground pipeline before sampling, so that microbial pollution in the pipeline is avoided;
Secondly, sample pretreatment: conveying the obtained stratum water sample to a room within 3h, firstly carrying out petroleum ether pretreatment on the sample, and centrifugally collecting thalli;
Extraction of DNA and PCR reaction: extracting the genome of the collected thalli by using a genome extraction kit, and amplifying a 16SV4 region in a sample DNA template by PCR reaction;
Fourthly, high-throughput sequencing and community structure analysis of samples: the high-throughput sequencing of the sample adopts an Illumina sequencing method; and after sequencing is completed, performing bioinformatics analysis to obtain the abundance of the carbonate mineralization bacteria in the oil reservoir water sample.
4. The method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation through microorganisms in the oil reservoir according to claim 1, wherein the microbial oil displacement mode of the oil reservoir is determined according to the abundance of carbonate mineralization bacteria in the formation water of the oil reservoir, and if the abundance of the carbonate mineralization bacteria is less than 1%, the microbial oil displacement mode of an external source is adopted; if the abundance of the carbonate mineralized bacteria is more than or equal to 1 percent, an endogenous microbial oil displacement mode is adopted.
5. The method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation by microorganisms in the oil reservoir according to claim 1, wherein the screening of the exogenous microorganisms comprises the following steps: adding 100ml of formation water and 2-5ml of exogenous microorganism and a nutrition system into a triangular flask with the volume of 250ml, and then adding quartz sand with the composition consistent with that of reservoir sand bodies of an oil reservoir; and (3) placing the triangular flask at the oil reservoir temperature, culturing for 20-30d, and screening out exogenous microorganisms with the pH value of more than 7 or the sand body at the bottom of the triangular flask converted from a loose state to a cemented state and the cemented sand body tolerance pressure of more than or equal to 15MPa in the system.
6. The method for improving reservoir heterogeneity according to claim 5, wherein the exogenous microorganism is one or more of Bacillus pasteurii, Bacillus licheniformis and Bacillus subtilis.
7. The method for improving the heterogeneity of an oil reservoir through mineral precipitation induced by microorganisms in the oil reservoir according to claim 5, wherein the nutrient system comprises 10-20 g/L of a carbon source and 5-10 g/L, NaCl 5-10 g/L of a nitrogen source, the carbon source is one of corn steep liquor hydrolysate, glucose and sucrose, and the nitrogen source is one of urea, beef extract, peptone and ammonium chloride.
8. the method for improving the heterogeneity of a reservoir by inducing mineral precipitation by microorganisms in the reservoir according to claim 1, wherein the specific method for screening the activating agent is as follows: adding 100ml of formation water and 2-5ml of activating agent into a triangular flask with the volume of 250ml, then adding quartz sand consistent with the composition of reservoir sand bodies of an oil reservoir, placing the triangular flask at the temperature of the oil reservoir, culturing for 15-20 days, and screening out the activating agent with the pH value of more than 7 or the activating agent with the capability of converting the sand bodies at the bottom of the triangular flask from a loose state into a cemented state and the cemented sand bodies with the tolerance pressure of more than or equal to 15 MPa.
9. The method for improving the heterogeneity of an oil reservoir through mineral precipitation induced by microorganisms in the oil reservoir according to claim 8, wherein the activating agent comprises 0.3-0.5 wt% of a carbon source, 0.3-0.5 wt% of a nitrogen source, 0.5-1 wt% of calcium ions, 0.5-1 wt% of sodium carbonate and 0.03-0.05 wt% of a biological polysaccharide, the carbon source comprises one of glucose, sucrose, starch, molasses and whey, the nitrogen source comprises one of beef extract, peptone, peanut cake powder and amino acids, and the biological polysaccharide comprises one of polysaccharide, heteropolysaccharide and glycoconjugate.
10. The method of improving reservoir heterogeneity according to claim 8 wherein the activator has a viscosity of 20 to 50 mPa-s.
11. the method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation by microorganisms in the oil reservoir according to claim 1, wherein the determination of the in-situ injection process comprises the following specific steps: filling two groups of sand-filled rock cores, wherein the range of the rock core group is consistent with the range of the test block; secondly, respectively vacuumizing the formation water of the saturated test block of the two groups of rock cores, and calculating the pore volume; placing the two groups of cores at the oil reservoir temperature of the test block to saturate the crude oil of the test block, and aging the cores for 7 d; connecting the two groups of rock cores in parallel and carrying out primary water flooding at the speed of 1.0-1.5 ml/min until the water content of produced liquid is consistent with the comprehensive water content of the test block, and simultaneously measuring the water phase permeability k of the two groups of rock cores when the water content of the produced liquid is consistent with the comprehensive water content of the test blocklow 1And kHeight 1(ii) a Injecting the screened exogenous microorganisms or the activators into the rock core group in different injection modes, culturing for 15-30 d, and testing the water phase permeability k of the two rock cores respectivelyLow 2And kHeight 2(ii) a Screening out low permeability core plugging rate etaIs low inLess than or equal to 2 percent and high-permeability core plugging rate etaHeight ofThe injection mode of more than or equal to 50 percent is the best field injection process.
12. The method of improving reservoir heterogeneity according to claim 11 wherein the injecting comprises slug injection and continuous injection.
13. The method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation through microorganisms in the oil reservoir according to claim 11, wherein the calculation formula of the core plugging rate η is as follows:
Wherein: k is a radical of1Initial determination of the core Water permeability, 10-3μm2；
k2After the cultivation the water phase permeability of the core, 10-3μm2。
14. the method for improving the heterogeneity of an oil reservoir by inducing mineral precipitation through microorganisms in the oil reservoir according to claim 1, wherein the field test and the evaluation of the effect comprise the following specific steps: and injecting exogenous microorganisms or an activating agent from the water injection well of the test block by using a high-pressure plunger pump according to the field injection process determined by the steps, and simultaneously evaluating the field test effect, wherein the evaluation indexes comprise the recovery efficiency improvement, the heterogeneity improvement degree and the validity period.
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| CN113202444A (en) * | 2021-05-12 | 2021-08-03 | 南方科技大学 | Natural gas hydrate reservoir strengthening method |
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Application publication date: 20191213 |