Deep hole etching acidification method suitable for high-calcium reservoir

Abstract

The invention discloses a deep hole etching acidification method suitable for a high-calcium reservoir, and belongs to the technical field of oil and gas field yield increase. The method comprises the following steps: acquiring geological data; the construction displacement and the construction pressure of injection of working fluid are determined, and the working fluid comprises permeation enhancing hole corrosion acid, hole corrosion precipitation liquid and hole expanding acid; the injection liquid amount of the working liquid is determined; injecting permeation-enhancing pore-etching acid into the reservoir, wherein the permeation-enhancing pore-etching acid is composed of 3-10% of permeation-enhancing agent and 90-97% of pH response phase change pore-etching acid; injecting hole corrosion eluate into the reservoir, wherein the hole corrosion eluate is a methanol or ethanol solution with the concentration higher than 80%; closing the well for 2-3 hours; injecting chambering acid into the reservoir, wherein the chambering acid consists of acid liquor, a soluble consolidation agent, a comprehensive additive and water; displacing fluid is injected; and closing the well and flowback. Complex, netted and multi-branch acid etching wormholes can be formed in the reservoir, acid etching channels can be effectively supported under high pressure, the acidification effect of the reservoir is further improved, and the method has important significance on yield increasing transformation of the high-calcium reservoir.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas field production increase, and in particular relates to a deep pitting acidification method suitable for high-calcium reservoirs. Background Art

[0002] Increasing production is the main measure for oil and gas well transformation. Especially for high-calcium reservoirs, acid treatment is the most effective measure to increase production. High-calcium reservoirs refer to carbonate reservoirs or sandstone reservoirs with high carbonate content. Since carbonates react easily with acids, the simplest way to transform high-calcium reservoirs is to use a hydrochloric acid system: 2HCl + CaCO3 = CaCl2 + H2O +CO2 The mechanism of acidizing to increase production is that reservoir minerals and blockages are dissolved to form new oil and gas channels. However, the channels formed by acid etching may collapse and close under reservoir pressure, so the goal of acidizing operation is to form effective acid etching channels.

[0003] There are two types of existing acid treatment measures: acid fracturing and matrix acidification. Whether it is acid fracturing or matrix acidification, acid-etched holes, pits, trenches and other flow channels are formed in the reservoir by acid dissolving reservoir minerals. The reservoir has been under high pressure. After the construction is completed, the acid-etched channels will shrink or even close under high pressure, especially in reservoirs with low rock strength and loose mineral cementation. The acid-etched channels will gradually close or even disappear under reservoir pressure. Therefore, to improve the effect of acid treatment, two factors must be considered: on the one hand, the acid can efficiently dissolve reservoir minerals and form acid-etched channels; on the other hand, the channels formed by acid etching can be effectively maintained under high pressure in the reservoir.

[0004] The focus of acid treatment technology is on the development of acid systems and the adjustment of acid injection processes. The development direction of acid systems is mostly slow and high temperature resistant, mainly including autogenous acid, thickened acid, organic acid, variable viscosity acid, cross-linked acid, chelated acid, etc. The acid injection processes include alternating acid fracturing, pre-fluid acid fracturing, closed acid fracturing, etc. There are many factors that affect the effect of acid treatment, mainly the following two points: (1) The acid-carbonate mineral reaction rate is fast, and it is very easy to form acid wormholes, but the acid wormholes are easy to close under high pressure, especially when the reservoir minerals have high mud content and loose cementation, making it difficult for the acid erosion surface to support under high pressure; (2) Fast-reacting acid is easy to form a high-channel main hole near the wellbore, that is, to form a similar short and wide fracture, and slow-reacting acid forms a similar slender fracture. The short and wide fractures connect the reservoir area with a small area, and the slender fractures have a large affected area, but the slender fractures are easy to close under high pressure. How to form complex, network-shaped, multi-branched acid pores and effectively support the acid erosion area under high pressure is the goal pursued by carbonate rock acidizing technology.

[0005] As a non-renewable resource, the physical properties of oil field reservoirs are getting worse and worse. Thin interlayers, mud, looseness, and mixed accumulation are all challenges faced by oil production. Especially for high-calcium reservoirs, how to form complex, network-like, multi-branched acid-etched pores and maintain high permeability under high pressure is a key technology to improve the acidizing effect and maintain the effective period of acidizing. Summary of the invention

[0006] The purpose of the present invention is to provide a deep pore acidizing method suitable for high-calcium reservoirs. The method is easy to operate and can form complex, reticular, multi-branched acid pores in the reservoir, achieve deep acid etching, expand the affected area of ​​acid etching, and effectively support the acid etching channel under high pressure, overcoming the shortcomings and defects of the current reservoir acidizing technology, especially for high-calcium reservoirs with high mud content and loose cementation, solving the problems of reservoir collapse after acidizing, acid etching channels being unable to support, and acid solution acting only in the near-wellbore area. The present invention further improves the reservoir acidizing effect, and is of great significance for the production increase and transformation of high-calcium reservoirs.

[0007] In order to achieve the above technical objectives, the present invention adopts the following technical solutions.

[0008] Reservoir minerals are divided into two categories: calcareous components M Ca and siliceous component M Si , M Ca + M Si = 100%. The sum of the mass percentages of dolomite, limestone and siderite is M Ca , the remaining component is the siliceous component M Si Siliceous component M Si Divided into mud component M m and hard silicon component M q , M Si = M m + M q , hard silicon component M q M is the sum of the mass proportions of quartz and feldspar in the mineral. Ca ≥50% of the reservoirs are high-calcium reservoirs, M m ≥ 10% of the reservoirs are high-argillaceous limestone reservoirs, M m Reservoirs with a concentration of less than 10% are conventional high-calcium reservoirs.

[0009] The deep cavitation acidification method applicable to high-calcium reservoirs comprises the following steps in sequence: S1 Obtain geological data, including reservoir mineral composition (calcium component M Ca Siliceous component M Si , mud component M m and hard silicon component M q ), reservoir permeability K, reservoir fracture pressure P f, average reservoir pressure P r and Ibuka H.

[0010] S2 Determine the construction displacement Q of the well fluid injection t and construction pressure P t The well fluid includes permeability-increasing pore-eroding acid, pore-eroding precipitate and pore-enlarging acid, and the process is as follows: S2-1 Determine the construction displacement and construction pressure of acid injection for permeability enhancement Reservoir cores or artificial cores (the permeability of artificial cores is close to that of reservoir cores) are used to set different flow rates for core displacement experiments of permeability-increasing pore acid, and the flow-pressure difference relationship curve is obtained to obtain the displacement pressure inflection point P. * , Displacement flow inflection point Q * , and obtain the construction displacement Q of the acid for increasing the permeability of the pore t , Construction pressure P t :

[0011] S2-2 Determine the construction displacement and construction pressure of the pore-etching solution and hole-expanding acid injection Construction discharge volume Q of pore-etching solution and pore-expanding acid t Value: 0.3-2m 3 / min, related to equipment parameters; Construction pressure P of pore-etching solution and pore-expanding acid t :

[0012] Where d is the core diameter, m; D is the diameter of the wellbore in the wellbore section, m; L is the length of the operating well section, m; ρ is the density of the well fluid, kg / m 3 ; P λ is the injection pressure loss of the well fluid, MPa; g is the acceleration due to gravity, m / s 2 ; λ is the friction coefficient of the well fluid; d t is the diameter of the pipe string for injecting well fluid (the diameter of the pipe in case of tubing construction and the diameter of the casing in case of casing construction), m; H is the well depth, m.

[0013] S3 Determine the amount of fluid injected into the well: Permeability enhancement acid: Determined by the length of the transformed well section, 0.5-2 m per meter 3 ; Etching solution: 0.3-0.5 times the volume of the etchant acid; Hole expansion acid: Determined by the length of the reformed well section, 2-6 m per meter 3 .

[0014] S4 injects permeability-enhancing pore acid into the reservoir according to the construction pressure and construction displacement obtained in S2, wherein the permeability-enhancing pore acid consists of 3-10% of a permeability enhancer and 90-97% of a pH-responsive phase-change pore acid, wherein the permeability enhancer is methanol, ethanol or acetone, and the pH-responsive phase-change pore acid consists of the following components in weight percentage: 10-20% of an acid generator, 10-30% of a pore expander, 1-2% of a coalescing agent, 0.5-10% of a pH adjuster, and the rest is water.

[0015] The acid generator is one or more of ammonium chloride, formaldehyde, methyl formate, ethyl acetate, and gluconolactone.

[0016] The pore expanding agent is one or more of sodium benzoate, disodium ethylenediaminetetraacetate, tetrasodium ethylenediaminetetraacetate, pentasodium diethylenetriaminepentaacetate, tetrasodium glutamate diacetate, sodium fumarate, benzoic acid, ethylenediaminetetraacetic acid, diethylenetriaminepentaacetic acid, diacetic glutamate, and fumaric acid.

[0017] The coalescing agent is one or more of ethylene glycol ethyl ether, ethylene glycol propyl ether, ethylene glycol butyl ether, ethylene glycol hexyl ether, diethylene glycol methyl ether, diethylene glycol ethyl ether, diethylene glycol butyl ether, diethylene glycol hexyl ether, propylene glycol n-butyl ether, dipropylene glycol n-butyl ether, dipropylene glycol methyl ether, tripropylene glycol methyl ether, propylene glycol phenyl ether, and propylene glycol tert-butyl ether.

[0018] The pH adjuster is one or more of formic acid, acetic acid, sodium formate and sodium acetate.

[0019] The preparation of the pore-increasing acid is as follows: 10-20% of an acid generator, 10-30% of a pore-enlarging agent, 1-2% of a coalescing agent and water are mixed and stirred evenly, and a pH regulator is added until the pH value of the solution is between 3 and 6.

[0020] S5: injecting cavitation solution into the reservoir according to the construction pressure and construction displacement obtained in S2, wherein the cavitation solution is a methanol or ethanol solution with a concentration higher than 80%.

[0021] S6 The well was shut in for 2-3 h, and complex micro-wormholes were formed in the reservoir.

[0022] S7 Inject pore-expanding acid into the reservoir according to the construction pressure and construction displacement obtained in S2, wherein the pore-expanding acid is composed of the following components in weight percentage: 10-20% acid solution, 0-20% soluble solidifying agent, 3-5% comprehensive additives, and the rest is water.

[0023] The acid solution is hydrochloric acid, acetic acid or formic acid; the soluble solidifying agent is one or more of oxalic acid, sodium oxalate, potassium oxalate, phosphoric acid, sodium phosphate, citric acid and sodium citrate; the comprehensive additive is composed of corrosion inhibitor, surfactant and mutual solvent, all of which are conventional additives used in oil field acidification.

[0024] The corrosion inhibitor is a commercially available corrosion inhibitor for oil field acidification, such as aldehyde, ketone and amine condensates, acetylene alcohols, thiourea and imidazoline derivatives.

[0025] The surfactant is a commercially available surfactant, such as a fluorocarbon surfactant or a quaternary ammonium salt surfactant.

[0026] The mutual solvent is a commercially available mutual solvent for oilfield acidification, such as ethylene glycol butyl ether, diethylene glycol butyl ether, and propylene glycol methyl ether.

[0027] Furthermore, conventional high-calcium reservoirs (M m <10%), no soluble consolidating agent is added to the pore-expanding acid; for high-argillaceous limestone reservoirs, a soluble consolidating agent is added to the pore-expanding acid.

[0028] S8 injects displacement fluid.

[0029] S9 Shut down the well for 1-5 hours and return the water.

[0030] Furthermore, the displacement fluid is 3% NH4Cl solution, 3% KCl solution or clean water, and the injection amount is 1.2-1.5 times the volume of the injection pipeline.

[0031] Furthermore, when the reservoir temperature is higher than 120°C, the shut-in time is 1-3 hours; when the reservoir temperature is lower than or equal to 120°C, the shut-in time is 2-5 hours.

[0032] The present invention utilizes an extremely slow-reacting acid-generating system (pore-increasing acid) and a fast-reacting acid (pore-expanding acid) to work synergistically to form complex acid-etched wormholes in high-calcium reservoirs. As a reservoir pretreatment liquid, the pore-increasing acid reacts extremely slowly when in contact with rocks, and only produces extremely weak gas-liquid two-phase resistance (negligible). Therefore, the pore-increasing acid enters the reservoir in a complex network seepage manner, and slowly reacts with calcium in the reservoir to form a complex acid-etched fine network. After further injection of pore-expanding acid, the pore-expanding acid-rock reaction quickly generates CO2 gas, forming a two-phase flow that makes it easier for the acid to enter the acid-etching network formed by the pore-increasing acid pretreatment, thereby forming a complex acid-etched wormhole network.

[0033] The mechanism of the present invention is analyzed as follows: First, the permeability-increasing porosity acid is a weak acid system, and its reaction rate is extremely low or no reaction occurs when it contacts with reservoir rocks (no reaction means no CO2 gas is generated, and no interfacial resistance of gas-liquid two-phase flow is formed). The small amount of alcohol in the permeability-increasing porosity acid system helps it enter various microchannels in the reservoir, that is, enter the complex seepage network; Second, after the acid generator in the system is injected into the reservoir, it slowly releases acid and combines with the pore expander to form solid organic acid particles. The coalescing agent further promotes the solid organic acid to aggregate into large particles. At the same time, the injected pore precipitate accelerates the solid organic acid to aggregate into large particles and precipitate and grow. Due to the growth of solid particles, it has an effective temporary blocking and diversion function during the injection process, which improves the efficiency of forming a complex seepage network. Third, the solid organic acid that has been formed slowly reacts with the calcium minerals in the reservoir to form a complex fine network with seepage capacity. At the same time, the solid organic acid gradually reacts into dissolved salts to achieve self-cleaning. Fourth, conventional acid will react quickly to produce CO2 upon contact with carbonate rocks in the reservoir, and great resistance will be generated during the acid injection process due to the gas-liquid two-phase flow. Especially in low-permeability areas, the two-phase resistance is greater due to the capillary force. At this time, the acid will only form a single acid-etching channel along the large pores and main fractures. In the present invention, based on the pretreatment of the permeability-enhancing pore-eroding acid, the injected pore-enlarging acid will enter the complex fine network, forming a complex acid-etched wormhole network with high permeability, achieving a high improvement ratio; Fifth, after the reservoir rock is dissolved by acid, the mechanical properties of the rock are reduced, making the reservoir prone to collapse, especially in high-argillaceous limestone reservoirs. After acid treatment, the mud becomes loose and migrates, resulting in poor acidizing effect or a short effective period. The soluble consolidating agent in the pore-expanding acid combines with the calcium ions after the acid reaction to form a hard supporting skeleton, consolidating some argillaceous minerals. That is, fast-reaction acid pore expansion and soluble consolidating agent support acid-etched holes, forming a complex acid-etched wormhole network, and can maintain a long-term supporting effect.

[0034] Compared with the prior art, the present invention has the following beneficial effects: 1. Utilizing the synergistic effect of various materials, on the basis of pretreatment with permeable pore-enhancing acid, the pore-enlarging acid enters into the complex fine network to form a complex acid-etched wormhole network with high permeability, expand the area affected by the acid-etching effect, and increase the improvement ratio of the acid treatment; 2. Use soluble consolidating agents to form a consolidation grid with calcium salts that react with acid during the shut-in time, which is equivalent to forming a support for the complex acid-etched wormhole network after acid etching, effectively supporting the acid-etched channel under reservoir pressure and extending the effective period of acidizing; 3. The present invention is suitable for acidification reconstruction construction of high-calcium reservoirs, especially for loose, porous reservoirs with high mud content, and the reconstruction effect is better. BRIEF DESCRIPTION OF THE DRAWINGS

[0035] Figure 1 It is a process flow chart of deep pitting acidizing method suitable for high-calcium reservoirs.

[0036] Figure 2 These are the CT morphology images of cores C1, C2, and C3 after the experiment.

[0037] Figure 3 These are the CT morphology images of cores D1 and D2 before and after the experiment. DETAILED DESCRIPTION

[0038] The present invention is further described below with reference to the accompanying drawings and examples, so that those skilled in the art can understand the present invention. However, it should be clear that the present invention is not limited to the scope of the specific embodiments, and for those skilled in the art, as long as various changes are within the spirit and scope of the present invention defined and determined by the attached claims, they are all protected. Example

[0039] A porous homogeneous high-calcium outcrop core was selected for core flow displacement experiment. Ca = 95%, which is a conventional high-calcium core with a core length of 8 cm and a diameter of 2.54 cm.

[0040] Pore-expanding acid: 15% HCl + 1% oily imidazoline + 1% fluorocarbon surfactant + 1% ethylene glycol butyl ether + 82% water.

[0041] Pore-increasing acid: 5% ethanol + 9.5% ammonium chloride + 9.5% formaldehyde + 14.25% sodium fumarate + 1.9% ethylene glycol ethyl ether + 57% water + 2.85% acetic acid, pH = between 3-4.

[0042] Etching solution: 80% ethanol solution.

[0043]

[0044] Note: 3% NH4Cl solution is used to test the permeability of the core. It does not react chemically with the core and has no effect on the core structure. The injection volume is based on the stability of the experiment during the test. K0 and K1 are the core permeabilities before and after the experiment, respectively.

[0045] Compare the permeability improvement data of the cores numbered C1, C2, and C3 before and after the experiment. C1 is better than C2, indicating that the pore-expanding acid has a stronger acid solubility than the permeability-increasing acid. C3 is much higher than the sum of the improvements of C1 and C2, indicating that the synergistic effect of the permeability-increasing acid and the pore-expanding acid greatly improves the improvement effect on the core permeability.

[0046] Figure 1 The core morphologies after experiments C1, C2, and C3 are shown. The cores improved by pore-expanding acid present main wormhole channels, and the cores improved by pore-increasing acid present multiple dispersed fine-mesh channels. Based on the improvement by pore-increasing acid, pore-expanding acid can further form enlarged complex meshes.

[0047] Example 2 The carbonate reservoir core of J oilfield was selected to carry out core flow displacement experiment. Ca = 79%, M Si = 21%, M q =18%, M m = 3%, the reservoir core is a conventional high-calcium core. The core length is 5 cm and the diameter is 2.54 cm.

[0048] Pore-expanding acid: 15% HCl + 1% oily imidazoline + 1% fluorocarbon surfactant + 1% ethylene glycol butyl ether + 82% water.

[0049] Pore-increasing acid: 10% ethanol + 9% gluconolactone + 9% diethylenetriamine pentaacetic acid pentasodium + 0.9% ethylene glycol butyl ether + 1.8% acetic acid + 69.3% water, pH = between 4-5.

[0050] Etching solution: 80% ethanol solution.

[0051]

[0052] Note: 3% NH4Cl solution is used to test the permeability of the core. It does not react chemically with the core and has no effect on the core structure. The injection volume is based on the stability of the experiment during the test. K0 and K1 are the core permeabilities before and after the experiment.

[0053] Comparing the permeability improvement data of the cores numbered D1 and D2 before and after the experiment, D2 is better than D1, which shows that the synergistic effect of the pore-increasing acid and the pore-expanding acid greatly improves the improvement effect on the core permeability.

[0054] Figure 2 The core morphology before and after the D1 and D2 experiments. D1 and D2 were initially dense and had almost no connected pores. After acid treatment, they showed excellent acid connection effects. The D1 core showed a main wormhole channel after pore expansion acid improvement, and eroded and flowed out from the side of the core. After the permeability-increasing pore acid and pore expansion acid acted together, the D2 core formed an enlarged complex mesh, and partially penetrated the interior of the core.

[0055] Example 3 Taking the X1 well engineering transformation of B oilfield as the implementation object, the deep cavitation acidizing method suitable for high-calcium reservoirs was used for transformation. The specific steps are as follows: S1 Obtain geological data of well X1 in oil field B. The mineral composition of the reservoir is: calcareous component M Ca = 76.3%, siliceous component M Si = 23.7%, mud component M m = 13.5%, hard silicon component M q= 10.2%, the target well reservoir is a high-mud limestone reservoir. The average gas permeability of the reservoir is K = 750 mD, and the reservoir fracture pressure is P f = 28 MPa, average reservoir pressure P r = 13MPa, well depth H = 1200 m, reservoir temperature T = 70℃.

[0056] S2 Determine the construction pressure P of the well fluid injection t , Construction displacement Q t , the process is as follows: S2-1 Determine the construction displacement and construction pressure of acid injection for permeability enhancement The cores sampled from the reservoir were used to conduct core displacement experiments with permeability-increasing pore acid at different flow rates. The flow-pressure difference relationship curve was obtained, and the displacement pressure inflection point P* = 0.6 MPa, the displacement flow inflection point Q* = 2.6 ml / min, the wellbore diameter of the entry section D = 0.2 m, the operating well section length L = 100 m, the core diameter d = 0.025 m, and the string diameter d t =0.1m, the construction displacement Q of acid injection in the permeability-increasing hole is calculated t Not more than 0.33 m 3 / min. Increasing permeability acid: λ=2.15, ρ =1250 kg / m 3 , P λ =7.9 MPa, the construction pressure P of acid injection in the permeability-increasing hole is calculated t Not more than 6.5 MPa; S2-2 Determine the construction displacement and construction pressure of the pore-etching solution and hole-expanding acid injection The construction discharge volume of the pore-etching solution and the hole-expanding acid is 1.5 m 3 / min; Pitting solution: λ=0.095, ρ=900 kg / m 3 , P λ =5.2 MPa, construction pressure of etchant solution P t Greater than 7.4 MPa and less than 22.4 MPa; Expanding acid: λ=0.12, ρ=1100 kg / m 3 , P λ =8.03 MPa, construction pressure of hole expansion acid P t Greater than 7.83 MPa and less than 22.83 MPa.

[0057] S3 Determine the amount of fluid injected into the well: Permeability-enhancing acid: 1 m per meter 3 , a total of 100 m3 ; Etching solution: 0.3 times the volume of the etchant acid, a total of 30 m 3 ; Expanding acid: 3 m per meter 3 , a total of 300 m 3 .

[0058] S4 Inject permeability-enhancing acid into the reservoir according to the construction pressure and construction displacement obtained in S2: 5% ethanol + 4.75% ammonium chloride + 4.75% formaldehyde + 4.75% gluconolactone + 4.75% sodium fumarate + 9.5% glutamic acid diacetic acid + 0.95% ethylene glycol butyl ether + 1.9% acetic acid + 63.65% water, pH = between 4-5.

[0059] S5 Inject the pore precipitate solution into the reservoir according to the construction pressure and construction displacement obtained in S2: 80% ethanol solution.

[0060] S6 was shut in for 3 h, and complex micro-wormholes were formed in the reservoir.

[0061] S7 Inject pore-expanding acid into the reservoir according to the construction pressure and construction displacement obtained in S2: 12% HCl + 6% oxalic acid + 1% oil-based imidazoline + 1% fluorocarbon surfactant + 1% ethylene glycol butyl ether + 79% water.

[0062] S8 Injection displacement fluid: 3% NH4Cl, 1.3 times the injection pipeline volume, the amount is about 12.2 m 3 .

[0063] S9 shut down the well for 5 hours and return the water.

[0064] Oilfield B is a newly developed oilfield. Conventional acidizing technology and shift acidizing technology were used in the early stage. However, due to the poor physical properties of the reservoir, the improvement effect was poor. After the deep cavitation acidizing method of high-calcium reservoir was adopted, the improvement ratio of a single well reached 6.8 times, and the production remained stable for more than 3 months after the improvement.

[0065] Example 4 Taking the J oilfield Z1 well engineering transformation as the implementation object, the deep cavitation acidizing method suitable for high-calcium reservoirs was used for transformation. The specific steps are as follows: S1 Obtain geological data of Well Z1 in J Oilfield. The mineral composition of the reservoir is: calcareous component M Ca = 81.9%, siliceous component M Si = 18.1%, mud component M m = 2.8%, hard silicon component M q = 15.32%, the target well reservoir is a high-calcareous reservoir. The average gas permeability of the reservoir is K = 46 mD, and the reservoir fracture pressure is Pf = 75 MPa, average reservoir pressure P r = 51MPa, well depth H = 4600 m, reservoir temperature T = 125℃.

[0066] S2 Determine the construction pressure P of the well fluid injection t , Construction displacement Q t , the process is as follows: S2-1 Determine the construction displacement and construction pressure of acid injection for permeability enhancement The cores sampled from the reservoir were used to conduct core displacement experiments with permeability-increasing pore acid at different flow rates to obtain the flow-pressure difference relationship curve and obtain the displacement pressure inflection point P. * = 7.1 MPa, displacement flow inflection point Q * =0.9ml / min, wellbore diameter D = 0.2m, operating well length L = 150m, core diameter d = 0.025m, string diameter d t =0.1m, the construction displacement Q of acid injection in the permeability-increasing hole is calculated t Not more than 0.173 m 3 / min. Increasing permeability acid: λ=2.15, ρ=1300 kg / m 3 , P λ =8.67MPa, construction pressure P of acid injection for permeability enhancement t Not more than 6.97 MPa; S2-2 Determine the construction displacement and construction pressure of the pore-etching solution and hole-expanding acid injection The construction discharge volume of the pore-etching solution and the pore-expanding acid is 2 m 3 / min; Pitting solution: λ=0.095, ρ=900 kg / m 3 , P λ =17.7Mpa, construction pressure of etchant solution P t Greater than 27.3 MPa and less than 51.3 MPa; Expanding acid: λ=0.12, ρ=1100 kg / m 3 , P λ =27.37 Mpa, construction pressure of hole expansion acid P t Greater than 27.77Mpa and less than 51.77Mpa.

[0067] S3 Determine the amount of fluid injected into the well: Permeability-enhancing acid: 1.2 m3 / m 3 , a total of 180 m 3 ; Etching solution: 0.5 times the volume of the etchant acid, a total of 90 m 3 ; Expanding acid: 5 m per meter 3 , a total of 750 m 3 .

[0068] S4 Inject permeability-enhancing acid into the reservoir according to the construction pressure and construction displacement obtained in S2: 10% ethanol + 9% gluconolactone + 9% diethylenetriamine pentaacetic acid pentasodium + 0.9% ethylene glycol butyl ether + 1.8% acetic acid + 69.3% water, pH = 4-5.

[0069] S5 Inject the pore precipitate solution into the reservoir according to the construction pressure and construction displacement obtained in S2: 80% ethanol solution.

[0070] S6 was shut in for 2 h, and complex micro-wormholes were formed in the reservoir.

[0071] S7 Inject pore-expanding acid into the reservoir according to the construction pressure and construction displacement obtained in S2: 20% HCl + 2% oil-based imidazoline + 1% fluorocarbon surfactant + 1% ethylene glycol butyl ether + 76% water.

[0072] S8 injection displacement fluid: 3% NH4Cl, 1.3 times the injection pipeline volume.

[0073] S9 shut down the well for 3 hours and return the water.

[0074] J Oilfield is a newly developed oilfield. In the early stage, conventional treatment measures such as clean acidizing and gelled acidizing were adopted, and the improvement ratio was about 5 times. After the deep etch acidizing method of high-calcareous reservoir was adopted, the improvement ratio of a single well reached 8.3 times.

Claims

1. A deep pitting acidification method suitable for high-calcium reservoirs, comprising the following steps in sequence: S1 Obtain geological data, including reservoir mineral composition, reservoir permeability K, reservoir fracture pressure P f , average reservoir pressure P r and Ibuka H; S2 Determine the construction displacement Q of the well fluid injection t and construction pressure P t , the well fluid includes permeability-enhancing pore-etching acid, pore-etching precipitate solution and pore-expanding acid; S3 determines the amount of fluid injected into the well; S4 injecting permeability-enhancing pore acid into the reservoir according to the construction pressure and construction displacement obtained in S2, wherein the permeability-enhancing pore acid is composed of 3-10% of a permeability enhancer and 90-97% of a pH-responsive phase-change pore acid, wherein the permeability enhancer is methanol, ethanol or acetone, and the pH-responsive phase-change pore acid is composed of the following components by weight percentage: 10-20% of an acid generating agent, 10-30% of a pore expanding agent, 1-2% of a coalescing agent, 0.5-10% of a pH adjusting agent, and the rest is water; The acid generator is one or more of ammonium chloride, formaldehyde, methyl formate, ethyl acetate, and gluconolactone; The pore expanding agent is one or more of sodium benzoate, disodium ethylenediaminetetraacetate, tetrasodium ethylenediaminetetraacetate, pentasodium diethylenetriaminepentaacetate, tetrasodium glutamate diacetate, sodium fumarate, benzoic acid, ethylenediaminetetraacetic acid, diethylenetriaminepentaacetic acid, diacetic glutamate, and fumaric acid; The coalescing agent is one or more of ethylene glycol ethyl ether, ethylene glycol propyl ether, ethylene glycol butyl ether, ethylene glycol hexyl ether, diethylene glycol methyl ether, diethylene glycol ethyl ether, diethylene glycol butyl ether, diethylene glycol hexyl ether, propylene glycol n-butyl ether, dipropylene glycol n-butyl ether, dipropylene glycol methyl ether, tripropylene glycol methyl ether, propylene glycol phenyl ether, and propylene glycol tert-butyl ether; The pH regulator is one or more of formic acid, acetic acid, sodium formate, and sodium acetate; S5 injecting a pitting solution into the reservoir according to the construction pressure and construction displacement obtained in S2, wherein the pitting solution is a methanol or ethanol solution with a concentration higher than 80%; S6 shuts in the well for 2-3 h, and complex micro-wormholes are formed in the reservoir; S7 injecting expansion acid into the reservoir according to the construction pressure and construction displacement obtained in S2, wherein the expansion acid is composed of the following components in weight percentage: 10-20% acid solution, 0-20% soluble consolidating agent, 3-5% comprehensive additives, and the rest is water; The acid solution is hydrochloric acid, acetic acid or formic acid; The soluble coagulant is one or more of oxalic acid, sodium oxalate, potassium oxalate, phosphoric acid, sodium phosphate, citric acid, and sodium citrate; The comprehensive additive is composed of corrosion inhibitor, surfactant and mutual solvent, which are all conventional additives used in oil field acidification; S8 injects displacement fluid; S9 Shut down the well for 1-5 hours and return the water.

2. The deep pitting acidification method applicable to high-calcium reservoirs according to claim 1, characterized in that: In step S1, the reservoir mineral component refers to the calcium component M Ca 、Silica component M Si , mud component M m and hard silicon component M q .

3. The deep pitting acidification method applicable to high-calcium reservoirs according to claim 1, characterized in that: The process of step S2 is as follows: S2-1 Determine the construction displacement and construction pressure of acid injection for permeability enhancement Reservoir cores or artificial cores were used to set different flow rates to conduct core displacement experiments with permeability-increasing acid, and the flow-pressure difference relationship curve was obtained to obtain the displacement pressure inflection point P. * , Displacement flow inflection point Q * , and obtain the construction displacement Q of the acid for increasing the permeability of the pore t , Construction pressure P t : ； S2-2 Determine the construction displacement and construction pressure of the pore-etching solution and hole-expanding acid injection Construction discharge volume Q of pore-etching solution and pore-expanding acid t Value: 0.3-2m 3 / min, related to equipment parameters; Construction pressure P of pore-etching solution and pore-expanding acid t : ； Where d is the core diameter, m; D is the diameter of the wellbore in the wellbore section, m; L is the length of the operating well section, m; ρ is the density of the well fluid, kg / m 3 ; P λ is the injection pressure loss of the well fluid, MPa; g is the acceleration due to gravity, m / s 2 ; λ is the friction coefficient of the well fluid; d t is the diameter of the pipe string for injecting well fluid, m; H is the well depth, m.

4. The deep pitting acidification method applicable to high-calcium reservoirs according to claim 1, characterized in that: The step S3 comprises: Permeability enhancement acid: Determined by the length of the transformed well section, 0.5-2 m per meter 3 ; Etching solution: 0.3-0.5 times the volume of the etchant acid; Hole expansion acid: Determined by the length of the reformed well section, 2-6 m per meter 3 .

5. The deep pitting acidification method applicable to high-calcium reservoirs according to claim 1, characterized in that: In step S4, the pore-increasing acid is prepared as follows: 10-20% of an acid generator, 10-30% of a pore-enlarging agent, 1-2% of a coalescing agent and water are mixed and stirred uniformly, and a pH adjuster is added until the pH value of the solution is between 3-6.

6. The deep pitting acidification method applicable to high-calcium reservoirs according to claim 1, characterized in that: In step S7, for conventional high-calcium reservoirs, no soluble consolidating agent is added to the pore-expanding acid; for high-argillaceous limestone reservoirs, a soluble consolidating agent is added to the pore-expanding acid.

7. The deep pitting acidification method applicable to high-calcium reservoirs according to claim 1, characterized in that: In step S7, the corrosion inhibitor is an aldehyde, ketone and amine condensate, acetylenic alcohol, thiourea or imidazoline derivative, the surfactant is a fluorocarbon surfactant or a quaternary ammonium salt surfactant, and the mutual solvent is ethylene glycol butyl ether, diethylene glycol butyl ether or propylene glycol methyl ether.

8. The deep pitting acidification method applicable to high-calcium reservoirs according to claim 1, characterized in that: In step S8, the displacement fluid is 3% NH4Cl solution, 3% KCl solution or clean water, and the injection amount is 1.2-1.5 times the volume of the injection pipeline.

9. The deep pitting acidification method applicable to high-calcium reservoirs according to claim 1, characterized in that: In step S9, when the reservoir temperature is higher than 120°C, the well shut-in time is 1-3 hours; when the reservoir temperature is lower than or equal to 120°C, the well shut-in time is 2-5 hours.

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