CN114594033A - Method for evaluating water sensitivity, water lock and solid phase damage of oil and gas reservoir - Google Patents
Method for evaluating water sensitivity, water lock and solid phase damage of oil and gas reservoir Download PDFInfo
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Abstract
The embodiment of the invention provides a method for evaluating water sensitivity, water lock and solid phase damage of an oil and gas reservoir, which comprises the following steps: drying, saturating formation water and performing first dehydration treatment on the core in sequence, and measuring the first gas permeability of the dehydrated core; reversely pressing the first dehydrated rock core into the solid-free fracturing fluid, standing, dehydrating the rock core for the second time, performing gas flooding, and measuring the second gas permeability of the rock core; calculating the water sensitivity damage rate of the rock core; reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas drive, standing, and measuring the third gas permeability of the core at a set pressure difference stage; calculating the water lock damage rate of the rock core; reversely injecting solid-phase-containing fracturing fluid into the core subjected to the third dehydration and gas flooding, standing, and removing a filter cake; measuring the fourth gas permeability of the rock core at a set pressure difference stage; the water lock damage rate of the core is calculated, the same core can be used, the water sensitivity, the water lock and the solid-phase damage of the core can be quantitatively evaluated, the cost is saved, and the operation is simple.
Description
Technical Field
The embodiment of the invention relates to the technical field of petroleum engineering reservoir protection, in particular to a method for evaluating water sensitivity, water lock and solid phase damage of an oil and gas reservoir.
Background
Clay and carbonate minerals, namely iron-containing minerals and the like generally exist in oil and gas reservoirs, and the reservoirs can be contacted with external liquid and solid particles thereof in each construction link of drilling, well cementation, well completion, perforation, production, water injection, well repair and production increase measures in the oil and gas exploration and development process. Because these fluids are incompatible with formation fluids to produce precipitates, or cause clay mineral swelling in the reservoir, or produce particulate migration, etc., the pore channels are blocked to reduce the permeability of the reservoir, and thus the reservoir sensitivity directly affects the productivity of the reservoir, even resulting in the inability to find or produce hydrocarbons.
Currently, common reservoir sensitivity evaluations include water sensitivity evaluation, water lock evaluation, and solid phase damage evaluation. And (3) independently carrying out a water sensitivity experiment, a water lock experiment and a solid phase damage experiment through different core experiments, and then testing the damage degree of each core so as to obtain the sensitivity characteristic of the reservoir.
However, the inventors found that the prior art has the following technical problems: in the prior art, a new core is required to be used for experiments every time, a large amount of experimental cores are required, and the experiment operation is complex and the cost is high.
Disclosure of Invention
The embodiment of the invention provides a method for evaluating water sensitivity, water lock and solid phase damage of an oil and gas reservoir, and aims to solve the problems that in the prior art, a new core is required to be used for an experiment every time, a large number of experiment cores are required, experiment operation is complicated, and cost is high.
The embodiment of the invention provides a method for evaluating water sensitivity, water lock and solid phase damage of an oil and gas reservoir, which comprises the following steps:
step A: drying, saturating formation water and carrying out first dehydration treatment on the core in sequence, and measuring the first gas permeability of the dehydrated core without slippage effect;
and B: reversely pressing the core after the first dehydration into the solid-free fracturing fluid, dehydrating the core for the second time after standing, then performing gas drive, wherein the gas drive direction is consistent with the centrifugal direction, establishing the saturation of the bound water of the core, and measuring the second gas permeability of the core without slippage effect;
and C: calculating the water-sensitive damage rate of the rock core according to the second gas permeability and the first body permeability;
step D: reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas flooding, stopping gas flooding when the core is subjected to very constant pressure gas flooding under the set pressure difference and is discharged back to the final production state of the simulated gas well, and measuring the third gas permeability of the core at the set pressure difference stage;
step E: calculating the water lock damage rate of the core according to the water sensitivity damage rate, the third gas permeability and the first body permeability;
step F: reversely injecting solid-phase-containing fracturing fluid into the core subjected to the third dehydration and gas flooding, standing, and removing a filter cake; performing very constant pressure gas drive on the core under the set pressure difference, and discharging to the final state of the production of the simulated gas well, ending the gas drive, and measuring the fourth gas permeability of the core at the set pressure difference stage;
step G: and calculating the water lock damage rate of the core according to the water sensitivity damage rate, the water lock damage rate, the fourth gas permeability and the first body permeability.
In one possible design, the step a includes:
and drying, saturating formation water and carrying out first dehydration treatment on the core in sequence, and measuring the first gas permeability of the dehydrated core without slippage effect.
In one possible design, the step B includes:
and reversely pressing the first dehydrated rock core into the solid-free fracturing fluid, standing, dehydrating the rock core for the second time, then performing gas drive, wherein the gas drive direction is consistent with the centrifugal direction, and measuring the second gas permeability of the rock core without slippage effect.
In one possible design, the step D includes:
reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas flooding, standing, performing very constant-pressure gas flooding on the core under a set pressure difference, and discharging to a final state of simulating gas well production to finish the gas flooding; and measuring the third gas permeability of the core at the set pressure differential stage.
In one possible design, the step F includes:
reversely injecting solid-phase-containing fracturing fluid into the core subjected to the third dehydration and gas flooding, standing, and removing a filter cake; performing very constant pressure gas drive on the rock core under a set pressure difference and discharging back to a final state for simulating gas well production, and ending the gas drive; and measuring the fourth gas permeability of the core at the set pressure differential stage.
In one possible design, step a further includes:
and respectively measuring the first T2 spectrum peak area, the second T2 spectrum peak area and the third T2 spectrum peak area after the rock core is dried, the formation water is saturated and the formation water is dehydrated by utilizing nuclear magnetic resonance equipment, and calculating the irreducible water saturation of the rock core according to the first T2 spectrum peak area, the second T2 spectrum peak area and the third T2 spectrum peak area.
In one possible design, step B further includes:
reversely pressing the first dehydrated rock core into the solid-free fracturing fluid, standing, dehydrating the rock core for the second time, then performing gas drive, wherein the gas drive direction is consistent with the centrifugal direction, and measuring the fourth T2 spectrum peak area of the rock core after establishing the irreducible water saturation of the rock core;
the step D further comprises the following steps:
reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas flooding, standing, and measuring the area of a fifth T2 spectrum peak of the core; performing very-constant-pressure gas drive on the rock core under the set pressure difference, and discharging back to the final production state of the simulated gas well, ending the gas drive, and respectively measuring the sixth T2 spectrum peak areas of the set pressure difference stage;
the step F further comprises the following steps:
reversely injecting a solid-phase-containing fracturing fluid into the dehydrated and gas-driven rock core for the third time, standing, removing a filter cake, and measuring the seventh T2 spectrum peak area of the rock core; and (3) performing very constant pressure gas drive on the rock core under the set pressure difference, returning and discharging to the final production state of the simulated gas well, ending the gas drive, and respectively measuring the eighth T2 spectrum peak area of the set pressure difference stage.
In one possible design, the peak area A is determined from the first T2 spectrum0Second T2 spectrum peak area A1And third T2 spectral peak area A2Calculating the coreIrreducible water saturation S, the formula is:
in one possible design, the simulated gas well production end state is 100 PV; the set pressure differential stages include 1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV and 100 PV.
In one possible design, before step a, the method further includes:
debugging nuclear magnetic resonance equipment, putting experimental formation water into the nuclear magnetic resonance equipment to test the peak area of a nuclear magnetic resonance signal of each experimental formation water, and establishing a corresponding relation between the peak area of a nuclear magnetic resonance T2 spectrum and the quality of the formation water through data fitting.
According to the method for evaluating the water sensitivity, the water lock and the solid phase damage of the oil and gas reservoir provided by the embodiment of the invention, the core is sequentially dried, saturated formation water and dehydrated for the first time, and the first gas permeability of the dehydrated core is measured; reversely pressing the first dehydrated rock core into the solid-free fracturing fluid, standing, dehydrating the rock core for the second time, performing gas flooding, and measuring the second gas permeability of the rock core; calculating the water-sensitive damage rate of the rock core; reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas flooding, standing, and measuring the third gas permeability of the core at the set pressure difference stage; calculating the water lock damage rate of the rock core; reversely injecting solid-phase-containing fracturing fluid into the core subjected to the third dehydration and gas flooding, standing, and removing a filter cake; measuring the fourth gas permeability of the rock core at a set pressure difference stage; the water lock damage rate of the core is calculated, the same core can be used, the water sensitivity, the water lock and the solid-phase damage of the core can be quantitatively evaluated, the cost is saved, and the operation is simple.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings needed to be used in the description of the embodiments or the prior art will be briefly introduced below, and it is obvious that the drawings in the following description are some embodiments of the present invention, and for those skilled in the art, other drawings can be obtained according to these drawings without creative efforts.
FIG. 1 is a schematic flow chart for evaluating water sensitivity, water lock and solid phase damage of a hydrocarbon reservoir according to an embodiment of the present invention;
FIG. 2 is a first schematic diagram illustrating the change of water lock damage during gas flooding according to an embodiment of the present invention;
fig. 3 is a schematic diagram illustrating a change of water lock damage in the gas flooding process according to an embodiment of the present invention.
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the drawings in the embodiments of the present invention, and it is obvious that the described embodiments are some, but not all, embodiments of the present invention. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
FIG. 1 is a schematic flow chart for evaluating water sensitivity, water lock and solid phase damage of a hydrocarbon reservoir according to an embodiment of the present invention. As shown in fig. 1, the method is as follows:
step A: and drying, saturating formation water and carrying out first dehydration treatment on the core in sequence, and measuring the first gas permeability of the dehydrated core without slippage effect.
In an embodiment of the present invention, before step a, the method further includes:
debugging nuclear magnetic resonance equipment, putting experimental formation water into the nuclear magnetic resonance equipment to test the peak area of a nuclear magnetic resonance signal of each experimental formation water, and establishing a corresponding relation between the peak area of a nuclear magnetic resonance T2 spectrum and the quality of the formation water through data fitting.
Wherein, debugging the nuclear magnetic resonance equipment comprises: placing a test coil in a nuclear magnetic resonance magnet, opening a nuclear magnetic resonance radio frequency switch, and opening nuclear magnetic resonance T2 spectrum test software; placing a standard sample of copper sulfate aqueous solution into the test coil, and calibrating the central frequency and the offset frequency; adjusting parameters of a nuclear magnetic resonance instrument such as TE (echo time), TR (sampling waiting time) and superposition times; the sample of the copper sulfate aqueous solution in the coil was taken out.
In this embodiment, step a specifically includes: drying the rock core, saturating formation water and dehydrating for the first time in sequence, respectively measuring a first T2 spectrum peak area, a second T2 spectrum peak area and a third T2 spectrum peak area after the rock core is dried, the saturated formation water and dehydrated by utilizing nuclear magnetic resonance equipment, and calculating the saturation of the bound water of the rock core according to the first T2 spectrum peak area, the second T2 spectrum peak area and the third T2 spectrum peak area; and measuring the first gas permeability of the dehydrated core without slippage effect.
Specifically, drying and weighing the dry weight of the core, and testing a first peak area A of a nuclear magnetic resonance T2 spectrum of the dry core by using nuclear magnetic resonance equipment0(ii) a After vacuumizing, the formation water is saturated for 12 hours, the wet weight is weighed, a T2 spectrum after the rock core is tested by utilizing nuclear magnetic resonance equipment to test the formation water is saturated, and a second peak area A is recorded1。
Removing formation water from the rock core after the formation water is saturated for 1.5 hours, then performing gas drive 100PV (simulating the final production state of a gas well), wherein the gas drive direction is consistent with the centrifugal direction, establishing the irreducible water saturation of the rock core, testing the T2 spectrum of the dehydrated rock core, and recording the third peak area A2。
According to the first T2 spectrum peak area A0Second T2 spectrum peak area A1And peak area A of the T2 th spectrum2And calculating the irreducible water saturation S of the rock core.
Wherein
Placing the dehydrated rock core into a special holder for nuclear magnetic resonance, and measuring the first gas permeability K of the rock core without slippage effect0。
In the embodiment, the irreducible water saturation is calculated and used for measuring the volume occupied by the irreducible water in the core pore space, the passing capacity can be influenced after the similar pipeline is partially blocked, and the irreducible water saturation and permeability relation can be formed by calculating the relation between different irreducible water saturations and the core permeability. Under the influence of bound water, the permeability of the rock core is reduced, and compared with the permeability of the first gas permeability (without influence of water), the influence rate of different bound water on the anhydrous rock core (without influence of water) can be evaluated.
And B: and reversely pressing the core after the first dehydration into the solid-free fracturing fluid, dehydrating the core for the second time after standing, then performing gas drive, wherein the gas drive direction is consistent with the centrifugal direction, establishing the irreducible water saturation of the core, and measuring the second gas permeability of the core without slippage effect.
In this embodiment, the step B specifically includes:
reversely pressing the first dehydrated rock core into the solid-free fracturing fluid, standing, dehydrating the rock core for the second time, then performing gas drive, wherein the gas drive direction is consistent with the centrifugal direction, establishing the saturation of the bound water of the rock core, and measuring the fourth T2 spectrum peak area of the rock core; and measuring a second gas permeability of the core without a slip effect.
Specifically, the dehydrated rock core is reversely pressed into 1PV solid-free fracturing fluid, the rock core is dehydrated for 1.5 hours after standing for 12 hours, then gas flooding 100PV is carried out, the gas flooding direction is consistent with the centrifugal direction, the irreducible water saturation of the rock core is established, a T2 spectrum of the rock core is tested, and the peak area A of a fourth T2 spectrum is recorded3(ii) a Measuring the second gas permeability K of the dehydrated rock core which is put into a special holder for nuclear magnetic resonance and has no slippage effect1。
And C: and calculating the water-sensitive damage rate of the core according to the second gas permeability and the first body permeability.
In the present embodiment, according to the second gas permeability K1And first body permeability K0Calculating the water-sensitive damage rate D of the rock core1The formula is:
step D: and reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas drive, standing, performing very-constant-pressure gas drive on the core under the set pressure difference, discharging to the final production state of the simulated gas well, ending the gas drive, and measuring the third gas permeability of the core at the set pressure difference stage.
In this embodiment, the step D specifically includes:
reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas flooding, standing, and measuring the area of a fifth T2 spectrum peak of the core; performing very constant pressure gas drive on the rock core under the set pressure difference, returning and discharging to the final state of the production of the simulated gas well, ending the gas drive, and respectively measuring the sixth T2 spectrum peak areas at the set pressure difference stage; and measuring the third gas permeability of the core at the set pressure differential stage.
Specifically, the core was back-squeezed into the solid-free fracturing fluid 1PV, left for 2 hours, and a nuclear magnetic resonance T2 spectrum (peak area of the fifth T2 spectrum) was measured. And (3) performing constant-pressure gas drive (gas type: wet nitrogen) on the rock core under the same pressure difference, returning to 100PV (simulating the final production state of the gas well), ending the gas drive, measuring the nuclear magnetic resonance T2 spectrum (the peak area of a sixth T2 spectrum) at different stages (1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV and 100PV), and testing the third gas permeability K at different stages2i(i represents the different stages of displacement 1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV, 100 PV).
Step E: and calculating the water lock damage rate of the core according to the water sensitivity damage rate, the third gas permeability and the first body permeability.
In this embodiment, the water lock damage rate of the core is calculated according to the water sensitive damage rate, the third gas permeability and the first bulk permeability, and the process is as follows:
according to third gas permeability K2iAnd first body permeability K0Calculating the total damage rate D of the rock cores in different stagestiSubtracting the water sensitive injury D1The water lock damage D of the rock core at different stages can be obtained2i. The calculation formula is as follows:
D2i＝Dti-D1 (4)
step F: reversely injecting solid-phase-containing fracturing fluid into the core subjected to the third dehydration and gas flooding, standing, and removing a filter cake; and (3) performing very constant pressure gas drive on the rock core under the set pressure difference, discharging back to the final production state of the simulated gas well, ending the gas drive, and measuring the fourth gas permeability of the rock core at the set pressure difference stage.
In this embodiment, step F specifically includes: reversely injecting a solid-phase-containing fracturing fluid into the dehydrated and gas-driven rock core for the third time, standing, removing a filter cake, and measuring the seventh T2 spectrum peak area of the rock core; performing very constant pressure gas drive on the rock core under the set pressure difference, returning and discharging to the final state of the production of the simulated gas well, ending the gas drive, and respectively measuring the eighth T2 spectrum peak areas at the set pressure difference stage; and measuring the fourth gas permeability of the core at the set pressure differential stage.
Specifically, the core was squeezed back into the 1PV solid-phase-containing fracturing fluid filtrate, left for 2 hours, the filter cake was removed, and the nmr T2 spectrum (peak area of seventh T2 spectrum) was weighed and measured. Performing constant-pressure gas drive (gas type: wet nitrogen) on the core under the same pressure difference, returning to 100PV, ending the gas drive, measuring the nuclear magnetic resonance T2 spectrum (eighth T2 spectrum peak area) at different stages (1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV and 100PV), and measuring the fourth gas permeability K at different stages3j(j represents the different stages of displacement 1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV, 100 PV).
Step G: and calculating the water lock damage rate of the core according to the fourth gas permeability and the first body permeability.
In this embodiment, the water lock damage rate of the core is calculated according to the water sensitivity damage rate, the water lock damage rate, the fourth gas permeability, and the first body permeability, and the process is as follows:
according to fourth gas permeability K3jAnd first body permeability K0Calculating the total damage rate D of the rock cores in different stagestjSubtracting the water-sensitive damage Dti(i ═ j), the water lock damage D of cores at different stages can be obtained3j. The calculation formula is as follows:
D3j＝Dtj-Dti(i＝j) (6)
from the above example, the method of the embodiment can be used for performing an experiment by using the same core, quantitatively give the water sensitivity, the water lock and the solid-phase damage of the gas reservoir core, save the experiment cost and be simple to operate.
Meanwhile, the conventional reservoir damage evaluation experiment and the nuclear magnetic resonance detection technology are organically combined, so that the water sensitivity, the water lock and the solid-phase damage of the rock are described more intuitively.
It should be noted that: by calculating the areas of the first to eighth T2 spectral peaks and according to the corresponding relation between the area of the T2 spectral peak and the formation water quality, the corresponding relation between the change of the formation water quality and the change of the gas permeability in the rock core is further obtained, and reference is provided for evaluating water sensitivity, water lock and solid-phase damage of the gas reservoir rock core.
The present invention is further illustrated with reference to the following specific examples, but the scope of the invention is not limited thereto.
Example 1
The physical properties of the gas reservoir core used in example 1 are shown in table 1.
TABLE 1 core Property parameter Table
The experimental procedure was as follows:
(1) debugging nuclear magnetic resonance equipment.
(2) And (4) scaling formation water. And placing the standard sample bottles containing different formation waters into the coil, testing the peak areas of the nuclear magnetic resonance signals of the different formation waters, and forming a corresponding relation between the nuclear magnetic resonance T2 spectrum peak area and the formation water quality through data fitting.
(3) Drying and weighing dry weight of the core, testing the T2 spectrum of the dry core, and recording the peak area A0Vacuum-pumping saturated formation water for 12 hours, weighingHeavily, testing the T2 spectrum of the saturated formation water of the rock core by using nuclear magnetic resonance equipment, and recording the peak area A1。
(4) Drying and weighing dry weight of the core, testing the T2 spectrum of the dry core, and recording the peak area A0Vacuumizing to saturate formation water for 12 hours, weighing wet weight, testing T2 spectrum of rock core saturated formation water by utilizing nuclear magnetic resonance equipment, and recording peak area A1。
(5) Placing the rock core into a special holder for nuclear magnetic resonance, and measuring the gas permeability K without slippage effect of the rock core0＝0.125043mD。
(6) Reversely extruding the core into 1PV solid-free fracturing fluid, standing for 12 hours, centrifugally dewatering the core for 1.5 hours, then gas-driving 100PV, wherein the direction is consistent with the centrifugal direction, establishing the saturation of the bound water after water-sensitive damage, testing a T2 spectrum, and determining the gas permeability K without slippage effect of the core in the holder1＝0.0997443mD。
(7) Obtaining the water-sensitive damage rate D of the rock core by comparing the permeability before and after the saturated solid-free fracturing fluid1＝20.23％。
(8) And reversely extruding the core into the solid-free fracturing fluid 1PV, standing for 2 hours, and measuring a nuclear magnetic resonance T2 spectrum.
(9) Performing constant-pressure gas drive (gas type: wet nitrogen) on the core under the same pressure difference (according to gas-water phase permeability standard) until the pressure is 100PV, ending the gas drive, measuring a nuclear magnetic resonance T2 spectrum at different stages (1PV, 4PV, 8PV, 16PV, 32PV, 50PV and 100PV) respectively, and testing the permeability (K) at different stages2iI represents the different stages of displacement 1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV, 100PV) the results are given in table 2.
TABLE 2 gas permeability and damage rate under different water saturation conditions
From the perspective of the water lock damage rate for displacing different PV numbers, the greater the displacement, the lower the water lock damage rate, see fig. 2. FIG. 2 is a first schematic diagram of water lock damage change in the gas flooding process.
(10) The core is reversely squeezed into 1PV solid-phase-containing fracturing fluid filtrate, because the permeability of the core is low, even if the pressure exceeds 20MPa when solid-phase-containing liquid is injected, the test cannot be completed within 24 hours, and for the low-permeability core, if the injection pressure exceeds 20MPa, data cannot be obtained, the pore throat is considered to be small, the solid-phase liquid cannot be immersed, and the solid-phase damage rate is 0.
(11) Taking displacement 100PV as an example, water-lock damage, water-sensitive damage, water-lock damage and solid-phase damage are respectively 20.23%, 38.53% and 0%, and relative damage rates are respectively 34.43%, 65.57% and 0%, so that for the core, water-lock damage is the largest, and water-sensitive damage is followed by no solid-phase damage.
Example 2
The physical properties of the gas reservoir core used in example 2 are shown in table 3.
TABLE 3 core Property parameter Table
(1) Debugging nuclear magnetic resonance equipment.
(2) And (4) scaling formation water.
(3) Drying and weighing dry weight of the core, testing the T2 spectrum of the dry core, and recording the peak area A0Vacuumizing to saturate formation water for 12 hours, weighing wet weight, testing T2 spectrum of rock core saturated formation water by utilizing nuclear magnetic resonance equipment, and recording peak area A1。
(4) Centrifuging the core for 1.5 hours to remove formation water, then performing gas drive on 100PV, wherein the direction is consistent with the centrifugal direction, establishing the irreducible water saturation of the core, testing the T2 spectrum after dehydration, and recording the peak area A2And calculating irreducible water saturation S in the core.
(5) Placing the rock core into a special holder for nuclear magnetic resonance, and measuring the gas permeability K without slippage effect of the rock core0＝2.845mD。
(6) Reversely extruding the rock core into 1PV solid-free fracturing fluid, standing for 12 hours, centrifugally dewatering the rock core for 1.5 hours, then gas-driving 100PV, wherein the direction is consistent with the centrifugal direction, and establishing waterThe saturation of the irreducible water after being sensitively damaged is tested by a T2 spectrum, and the gas permeability K without slippage effect of the core in the holder is determined1＝2.347mD。
(7) Obtaining the water-sensitive damage rate D of the rock core by comparing the permeability before and after the saturated solid-free fracturing fluid1＝17.50％。
(8) And reversely squeezing the rock core into the solid-free fracturing fluid 1PV, standing for 2 hours, and measuring a nuclear magnetic resonance T2 spectrum.
(9) Performing constant-pressure gas flooding (gas type: wet nitrogen) on the core under the same pressure difference (according to gas-water phase permeability standard) until the pressure is 100PV, ending the gas flooding, measuring the nuclear magnetic resonance T2 spectrum at different stages (1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV and 100PV) respectively, and testing the permeability (K) at different stages2iI represents the different stages of displacement 1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV, 100PV) the results are given in table 4.
(10) By comparing the permeability after extruding into the fracturing fluid without solid phase with K0To obtain the total damage rate D of the rock core at different stages of displacementtiRemoval of water sensitive injury D1The water lock damage D of the rock core at different stages can be obtained2iSee table 4. From table 4, it can be observed that the permeability gradually increases, the water lock damage rate gradually decreases, and the residual water saturation in the core after the gas flooding of 100PV is 55.74%, and the water lock damage rate is 31.74%.
TABLE 4 gas permeability and injury Rate for different Water saturation conditions
From the perspective of the water lock damage rate for displacing different PV numbers, the greater the displacement, the lower the water lock damage rate, see fig. 3. FIG. 3 is a schematic diagram of the change of water lock damage in the gas flooding process.
(11) And reversely extruding the core into 1PV solid-phase-containing fracturing fluid filtrate, standing for 2 hours, removing a filter cake, weighing and measuring a nuclear magnetic resonance T2 spectrum.
(12) Performing constant-pressure gas drive (gas type: wet nitrogen) on the rock core under the same pressure difference, and discharging back to 100PVMeasuring nuclear magnetic resonance T2 spectra at different stages (1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV, 100PV), testing permeability (K) at different stages3jAnd j represents the different stages of displacement 1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV, 100 PV).
(13) By comparing the permeability after squeezing into the filtrate containing the solid-phase fracturing fluid with K0To obtain the total damage rate D of the rock core at different stages of displacementtjRemoval of water sensitivity and water lock damage Dti(i ═ j), the solid phase damage rate D at different stages of displacement by the solid phase can be obtained3jSee table 5. The gradual increase in permeability can be observed from table 5, with a gradual decrease in total injury. However, the solid phase damage rate is not clearly reproducible at different PV values for displacement, and for gas displacement, it is generally assumed that the solid phase damage should be fixed, so the average value is taken as the solid phase damage rate of the whole, i.e. 4.02%.
TABLE 5 gas permeability and damage Rate for different Water saturation conditions
(14) The water-lock damage is exemplified by displacement 100PV, absolute values of water-sensitive, water-lock and solid-phase damage are 17.50%, 31.74% and 4.02% respectively, and relative damage rates are 32.86%, 59.59% and 7.55% respectively.
Finally, it should be noted that: the above embodiments are only used to illustrate the technical solution of the present invention, and not to limit the same; while the invention has been described in detail and with reference to the foregoing embodiments, it will be understood by those skilled in the art that: the technical solutions described in the foregoing embodiments may still be modified, or some or all of the technical features may be equivalently replaced; and the modifications or the substitutions do not make the essence of the corresponding technical solutions depart from the scope of the technical solutions of the embodiments of the present invention.
Claims (10)
1. A method for evaluating water sensitivity, water lock and solid phase damage of an oil and gas reservoir is characterized by comprising the following steps:
step A: drying, saturating formation water and carrying out first dehydration treatment on the core in sequence, and measuring the first gas permeability of the dehydrated core without slippage effect;
and B: reversely pressing the core after the first dehydration into the solid-free fracturing fluid, dehydrating the core for the second time after standing, then performing gas drive, wherein the gas drive direction is consistent with the centrifugal direction, establishing the saturation of the bound water of the core, and measuring the second gas permeability of the core without slippage effect;
and C: calculating the water-sensitive damage rate of the rock core according to the second gas permeability and the first body permeability;
step D: reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas flooding, stopping gas flooding when the core is subjected to very constant pressure gas flooding under the set pressure difference and is discharged back to the final production state of the simulated gas well, and measuring the third gas permeability of the core at the set pressure difference stage;
step E: calculating the water lock damage rate of the core according to the water sensitivity damage rate, the third gas permeability and the first body permeability;
step F: reversely injecting solid-phase-containing fracturing fluid into the core subjected to the third dehydration and gas flooding, standing, and removing a filter cake; the gas drive is finished when the rock core is subjected to very constant pressure gas drive back drainage under the set pressure difference to a final state for simulating the production of a gas well, and the fourth gas permeability of the rock core at the set pressure difference stage is measured;
step G: and calculating the water lock damage rate of the core according to the water sensitivity damage rate, the water lock damage rate, the fourth gas permeability and the first body permeability.
2. The method of claim 1, wherein step a comprises:
and drying, saturating formation water and carrying out first dehydration treatment on the core in sequence, and measuring the first gas permeability of the dehydrated core without slippage effect.
3. The method of claim 2, wherein step B comprises:
and reversely pressing the first dehydrated rock core into the solid-free fracturing fluid, standing, dehydrating the rock core for the second time, then performing gas drive, wherein the gas drive direction is consistent with the centrifugal direction, and measuring the second gas permeability of the rock core without slippage effect.
4. The method of claim 3, wherein step D comprises:
reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas flooding, standing, performing very constant-pressure gas flooding on the core under a set pressure difference, and discharging to a final state of simulating gas well production to finish the gas flooding; and measuring the third gas permeability of the core at the set pressure differential stage.
5. The method of claim 4, wherein step F comprises:
reversely injecting solid-phase-containing fracturing fluid into the core subjected to the third dehydration and gas flooding, standing, and removing a filter cake; performing very constant pressure gas drive on the rock core under a set pressure difference, and ending the gas drive when the rock core returns to a final state simulating the production of the gas well; and measuring the fourth gas permeability of the core at the set pressure differential stage.
6. The method of claim 2, wherein step a further comprises:
and respectively measuring the first T2 spectrum peak area, the second T2 spectrum peak area and the third T2 spectrum peak area after the rock core is dried, the formation water is saturated and the formation water is dehydrated by utilizing nuclear magnetic resonance equipment, and calculating the irreducible water saturation of the rock core according to the first T2 spectrum peak area, the second T2 spectrum peak area and the third T2 spectrum peak area.
7. The method of claim 6,
the step B further comprises the following steps:
reversely pressing the first dehydrated rock core into the solid-free fracturing fluid, standing, dehydrating the rock core for the second time, then performing gas drive, wherein the gas drive direction is consistent with the centrifugal direction, and measuring the fourth T2 spectrum peak area of the rock core after establishing the irreducible water saturation of the rock core;
the step D further comprises the following steps:
reversely injecting the solid-free fracturing fluid into the core subjected to the second dehydration and gas flooding, standing, and measuring the area of a fifth T2 spectrum peak of the core; performing very constant pressure gas drive on the rock core under the set pressure difference, returning and discharging to the final state of the production of the simulated gas well, ending the gas drive, and respectively measuring the sixth T2 spectrum peak areas at the set pressure difference stage;
the step F further comprises the following steps:
reversely injecting a solid-phase-containing fracturing fluid into the dehydrated and gas-driven rock core for the third time, standing, removing a filter cake, and measuring the seventh T2 spectrum peak area of the rock core; and (3) performing very constant pressure gas drive on the rock core under the set pressure difference, returning and discharging to the final production state of the simulated gas well, ending the gas drive, and respectively measuring the eighth T2 spectrum peak area of the set pressure difference stage.
8. The method of claim 6, wherein the peak area A is determined from the first T2 spectrum0Second T2 spectrum peak area A1And third T2 spectral peak area A2Calculating the saturation S of the irreducible water of the rock core, wherein the formula is as follows:
9. the method of claim 1 wherein the simulated gas well production end state is 100 PV; the set pressure differential stages include 1PV, 2PV, 4PV, 8PV, 16PV, 32PV, 50PV and 100 PV.
10. The method according to any one of claims 6 to 8, characterized in that before step A, it further comprises:
debugging nuclear magnetic resonance equipment, putting experimental formation water into the nuclear magnetic resonance equipment to test the peak area of a nuclear magnetic resonance signal of each experimental formation water, and establishing a corresponding relation between the peak area of a nuclear magnetic resonance T2 spectrum and the quality of the formation water through data fitting.
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