A comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs

Abstract

The present invention relates to the technical field of oil and gas reservoirs, and particularly to a comprehensive identification method for the damage degree of carbonate low-porosity and low-permeability reservoirs, including identification before and after the development of carbonate low-porosity and low-permeability reservoirs; the identification before the development of carbonate low-porosity and low-permeability reservoirs refers to: identifying the potential reservoir damage factors existing in carbonate low-porosity and low-permeability reservoirs based on the initial reservoir and fluid parameters, and discriminating the sensitivity degree; the identification after the development of carbonate low-porosity and low-permeability reservoirs refers to: identifying the liquid loading and blockage conditions in the wellbore based on the gas well monitoring data, and judging whether liquid loading and scaling blockage occur in the wellbore; after there is no liquid loading and scaling blockage in the wellbore, identifying the water lock degree of the reservoir based on the gas well monitoring data, gas reservoir and fluid parameters, and obtaining the water lock damage range. Through this identification method, the potential damage and existing damage conditions of the reservoir before and after the development of carbonate low-porosity and low-permeability reservoirs can be quantitatively described.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas reservoirs, and particularly to a comprehensive identification method for the damage degree of carbonate low-porosity and low-permeability reservoirs. Background Art

[0002] The carbonate gas reservoirs in China are rich in reserves. However, the general survey and statistical data of gas fields in recent years show that most gas wells are shut down due to wellbore liquid accumulation and scaling, near-wellbore reservoir water blocking, plugging and other reasons, seriously affecting the productivity of gas fields. Therefore, accurately identifying the types and degrees of reservoir damage is of great significance for guiding on-site plug removal construction.

[0003] At present, most of the carbonate low-porosity and low-permeability reservoir damage identification technologies only target single factors such as wellbore liquid accumulation, scaling or formation water blocking damage, and a comprehensive identification technology for multiple reservoir damage factors has not been formed. The existing identification methods mainly rely on indoor core simulation experiments for analysis, which cannot simulate the actual underground situation, and the obtained results cannot be extended to the entire formation block, resulting in inaccurate identification. Summary of the Invention

[0004] To solve the above technical problems, the present invention proposes a comprehensive identification method for the damage degree of carbonate low-porosity and low-permeability reservoirs, which can effectively solve the problem of inaccurate existing identification methods, and can quantitatively describe the potential damage and existing damage conditions of carbonate low-porosity and low-permeability reservoirs before and after development.

[0005] The present invention is realized by adopting the following technical solutions:

[0006] A comprehensive identification method for the damage degree of carbonate low-porosity and low-permeability reservoirs, characterized in that it includes identification before the carbonate low-porosity and low-permeability reservoirs are put into development and identification after the carbonate low-porosity and low-permeability reservoirs are put into development;

[0007] Among them, the identification before the carbonate low-porosity and low-permeability reservoirs are put into development specifically includes the following steps:

[0008] S1. Identify the potential reservoir damage factors existing in the carbonate low-porosity and low-permeability reservoirs based on the initial reservoir and fluid parameters, and determine the sensitivity degree;

[0009] Among them, the identification after the carbonate low-porosity and low-permeability reservoirs are put into development specifically includes the following steps:

[0010] S2. Identify the wellbore liquid accumulation and plugging conditions based on the gas well monitoring data, judge whether the wellbore has liquid accumulation and scaling plugging. If so, perform construction to remove the wellbore liquid accumulation and plugging, and then enter step S3 after removal. If not, directly enter step S3;

[0011] S3. Identify the degree of reservoir water lock based on gas well monitoring data, gas reservoir formation and fluid parameters, and obtain the range of water lock damage.

[0012] Step S1 specifically includes the following steps:

[0013] S 11 . Obtain formation and fluid parameters for carbonate rock low-porosity and low-permeability reservoirs;

[0014] S 12 . Calculate the water-phase trapping index values of the reservoir according to the formation and fluid parameters. The water-phase trapping index values include the aqueous phase trapping index APT, the aqueous phase trapping factor PTC, and the aqueous phase trapping index CAPT applicable to gas reservoirs;

[0015] S 13 . Discriminate the sensitivity of potential water-phase trapping in carbonate rock low-porosity and low-permeability reservoirs according to the calculated water-phase trapping index values.

[0016] The formation and fluid parameters include reservoir gas permeability, porosity, initial water saturation, gas-water interfacial tension, contact angle, gas viscosity, water-phase viscosity, gas-water viscosity ratio, irreducible water saturation, and invasion depth.

[0017] The calculation method of the aqueous phase trapping index APT is:

[0018] APT = 0.25lgk + 2.2S wi

[0019] The calculation method of the aqueous phase trapping factor PTC is:

[0020]

[0021] The calculation method of the aqueous phase trapping index CAPT applicable to gas reservoirs is:

[0022]

[0023] In the formula: k is the gas permeability of the reservoir; S wi is the initial water saturation of the reservoir; is the porosity; σ is the gas-water interfacial tension; θ is the contact angle; μm is the gas-water viscosity ratio; △p is the maximum pressure difference provided by the oil and gas reservoir during fluid drainage; S wirr is the irreducible water saturation of the reservoir; μ g is the gas viscosity; μ w is the water-phase viscosity; I d is the invasion depth.

[0024] The said step S 13Specifically, it refers to: respectively discriminating the aqueous phase trapping index APT, the aqueous phase trapping factor PTC, and the aqueous phase trapping index CAPT applicable to gas reservoirs, and taking the maximum value of the discriminated results as the sensitivity of aqueous phase trapping damage.

[0025] Specifically, discriminating the aqueous phase trapping index APT means that if APT i ≥1.0, it is judged that the water lock damage is insensitive; if 0.8 ≤ APT i ≤1.0, it is judged that the water lock damage is relatively sensitive, and if APT i ≤0.8, it is judged that the water lock damage is very sensitive;

[0026] Specifically, discriminating the aqueous phase trapping factor PTC means that if PTC < 0.05, it is judged to be insensitive; if 0.05 ≤ PTC < 0.3, it is judged that the sensitivity is weak; if 0.3 ≤ PTC < 0.5, it is judged that the sensitivity is weak to medium; if 0.5 ≤ PTC < 0.7, it is judged that the sensitivity is medium to strong; if PTC ≥ 0.7, it is judged that the sensitivity is strong;

[0027] Specifically, discriminating the aqueous phase trapping index CAPT applicable to gas reservoirs means that if CAPT < 0.05, it is judged to be insensitive; if 0.05 ≤ CAPT < 0.3, it is judged that the sensitivity is weak; if 0.3 ≤ CAPT < 0.5, it is judged that the sensitivity is weak to medium; if 0.5 ≤ CAPT < 0.7, it is judged that the sensitivity is medium to strong; if CAPT ≥ 0.7, it is judged that the sensitivity is strong.

[0028] The method for judging whether liquid accumulation and scaling blockage occur in the wellbore includes the following steps:

[0029] S 21 . According to the gas production, water production, tubing inner diameter, gas-water density, and tubing wellhead pressure of the gas well, by dividing the wellbore into a series of well sections, iteratively calculating the pressure drop of each well section from the wellhead oil pressure, calculating the multiphase flow in the wellbore using the Hagedron-Brown model, and calculating the theoretical bottom-hole flowing pressure under normal production conditions of the gas well;

[0030] S 22 . According to the theoretical bottom-hole flowing pressure and the static gas column pressure in the tubing-casing annulus, calculate the theoretical casing wellhead pressure;

[0031] S 23 . Based on the gas-water interfacial tension and gas-water density, calculate the critical liquid-carrying gas volume of the gas well using the Turner model;

[0032] S 24 . Based on the actual gas production and actual tubing-casing pressure difference of the gas well, compare with the critical liquid-carrying gas volume and the theoretical tubing-casing pressure difference to discriminate the liquid accumulation and scaling blockage situation in the wellbore:

[0033] 1) If the actual gas production volume is lower than the critical liquid-carrying gas volume and the actual tubing-casing pressure difference exceeds the theoretical tubing-casing pressure difference, there may be liquid accumulation in the wellbore.

[0034] 2) If the actual gas production volume exceeds the critical liquid-carrying gas volume and the actual tubing-casing pressure difference exceeds the theoretical tubing-casing pressure difference, there may be a wellbore blockage.

[0035] The calculation method of the theoretical bottom-hole flowing pressure under normal production conditions of the gas well is as follows:

[0036]

[0037] ρ m = ρ1H1 + ρ g (1 - H1)

[0038] G m = G g + G1 = A(v sl ρ l + v sg ρ g )

[0039] In the formula: ρ is the fluid density; H l is the liquid holdup; A is the cross-sectional area of the tubing flow; D is the inner diameter of the tubing; G is the fluid mass flow rate, and v is the fluid volume flow rate;

[0040] The calculation method of the theoretical casing wellhead pressure is as follows:

[0041]

[0042] In the formula: P c is the theoretical casing wellhead pressure; P wf is the theoretical bottom-hole flowing pressure; γ is the relative density of the gas; H is the depth of the middle part of the gas reservoir; T is the average temperature of the wellbore; Z is the average deviation factor of the gas in the wellbore;

[0043] The calculation method of the critical liquid-carrying gas volume of the gas well is as follows:

[0044]

[0045] In the formula: v cr is the critical liquid-carrying gas volume of the gas well; k s is the safety factor; C d is the drag coefficient; ρ g 、ρ l are the densities of the gas and water.

[0046] Step S3 specifically includes the following steps:

[0047] S 31 . Obtain the production dynamic data of carbonate rock low-porosity and low-permeability reservoirs, fluids, and gas wells;

[0048] S 32 . Based on the stable gas flow state considering the effect of water block, establish a gas well productivity equation considering the effect of water block:

[0049]

[0050]

[0051]

[0052] S = S′ + S b

[0053]

[0054] Wherein: P e is the formation pressure of the gas reservoir; r e is the drainage radius; h is the effective thickness of the gas reservoir; q sc is the gas well production; K is the original permeability of the gas reservoir; S’ is the skin factor of reservoir damage caused by other factors except water block; Z is the gas deviation factor; ra is the water block radius; K a is the permeability after water block; S b is the skin factor caused by water block;

[0055] S 33 . According to the equation in step S 32 , use the Newton iteration method to iterate and solve the equation to obtain the water block radius and identify the range of reservoir water block damage:

[0056] f(r a ) = 0

[0057]

[0058]

[0059] Wherein: f represents the gas well productivity equation considering the effect of water block; the subscripts n and n + 1 represent the Newton iteration levels.

[0060] The production performance data includes the formation pressure of the gas reservoir, the supply radius, the effective thickness of the gas reservoir, the gas production of the gas well, the original permeability of the gas reservoir, the permeability after water block, the skin factor of reservoir damage, and the gas deviation factor.

[0061] Compared with the prior art, the beneficial effects of the present invention are shown in:

[0062] 1. Through this identification method, the reservoir damage factors and damage degrees before and after the development of carbonate rock low-porosity and low-permeability reservoirs can be identified.

[0063] 2. The present invention can comprehensively identify various damage factors such as wellbore liquid accumulation, scaling blockage, and reservoir water lock, quantitatively describe the potential damage and existing damage conditions of carbonate low-porosity and low-permeability reservoirs before and after development, and effectively guide the wellbore and reservoir plugging removal construction. Detailed implementation manners

[0064] Example 1

[0065] As a basic implementation manner of the present invention, the present invention includes a comprehensive identification method for the damage degree of carbonate low-porosity and low-permeability reservoirs, including identification before the development of carbonate low-porosity and low-permeability reservoirs and identification after the development of carbonate low-porosity and low-permeability reservoirs.

[0066] Among them, the identification before the development of carbonate low-porosity and low-permeability reservoirs means: identifying the potential reservoir damage factors existing in carbonate low-porosity and low-permeability reservoirs based on the initial reservoir and fluid parameters, and discriminating the sensitivity degree.

[0067] Among them, the identification after the development of carbonate low-porosity and low-permeability reservoirs means: identifying the wellbore liquid accumulation and blockage conditions based on the gas well monitoring data, judging whether liquid accumulation and scaling blockage occur in the wellbore, and if so, performing construction to relieve the wellbore liquid accumulation and blockage. And identifying the reservoir water lock degree based on the gas well monitoring data, gas reservoir reservoir and fluid parameters, and obtaining the water lock damage range.

[0068] Example 2

[0069] As a preferred implementation manner of the present invention, the present invention includes a comprehensive identification method for the damage degree of carbonate low-porosity and low-permeability reservoirs, including identification before the development of carbonate low-porosity and low-permeability reservoirs and identification after the development of carbonate low-porosity and low-permeability reservoirs.

[0070] Among them, the identification before the development of carbonate low-porosity and low-permeability reservoirs means: identifying the potential reservoir damage factors existing in carbonate low-porosity and low-permeability reservoirs based on the initial reservoir and fluid parameters, and discriminating the sensitivity degree. Specifically, it includes the following steps:

[0071] S 11 . Obtain reservoir and fluid parameters for carbonate low-porosity and low-permeability reservoirs;

[0072] S 12 . Calculate the water-phase trap index values of the reservoir according to the reservoir and fluid parameters, and the water-phase trap index values include the aqueous-phase trap index APT, the aqueous-phase trap factor PTC, and the aqueous-phase trap index CAPT applicable to gas reservoirs;

[0073] S 13 . According to the calculated water-phase trap index values, discriminate the sensitivity degree of potential water-phase trap in carbonate low-porosity and low-permeability reservoirs.

[0074] Among them, identification is carried out after the carbonate low-porosity and low-permeability reservoir is put into development, which specifically includes the following steps:

[0075] S2. Identify the liquid accumulation and blockage conditions in the wellbore based on the gas well monitoring data, and judge whether there is liquid accumulation and scaling blockage in the wellbore. If so, carry out construction to remove the liquid accumulation and blockage in the wellbore. After removal, enter step S3. If not, directly enter step S3;

[0076] S3. Identify the degree of water lock in the reservoir based on the gas well monitoring data, gas reservoir reservoir and fluid parameters, and obtain the range of water lock damage.

[0077] Among them, the method for judging whether there is liquid accumulation and scaling blockage in the wellbore in step S2 includes the following steps:

[0078] S 21 . According to the gas production, water production, inner diameter of the tubing, gas-water density and tubing wellhead pressure of the gas well, by dividing the wellbore into a series of well sections, iteratively calculate the pressure drop of each well section from the wellhead oil pressure, and use the Hagedron-Brown model to calculate the multiphase flow in the wellbore, and calculate the theoretical bottom hole flowing pressure under normal production conditions of the gas well;

[0079] S 22 . Calculate the theoretical casing wellhead pressure according to the theoretical bottom hole flowing pressure and the static gas column pressure in the annulus between the tubing and the casing;

[0080] S 23 . Calculate the critical liquid-carrying gas volume of the gas well by using the Turner model based on the gas-water interfacial tension and gas-water density;

[0081] S 24 . Based on the actual gas production of the gas well and the wellhead pressure of the tubing and casing, compare with the critical liquid-carrying gas volume and the theoretical tubing-casing pressure difference to judge the liquid accumulation and scaling blockage conditions in the wellbore:

[0082] 1) If the actual gas production is lower than the critical liquid-carrying gas volume, and the actual tubing-casing pressure difference exceeds the theoretical tubing-casing pressure difference, there may be liquid accumulation in the wellbore;

[0083] 2) If the actual gas production exceeds the critical liquid-carrying gas volume, and the actual tubing-casing pressure difference exceeds the theoretical tubing-casing pressure difference, there may be blockage in the wellbore.

[0084] Embodiment 3

[0085] As another preferred embodiment of the present invention, the present invention includes a comprehensive identification method for the damage degree of carbonate low-porosity and low-permeability reservoirs, including identification before the carbonate low-porosity and low-permeability reservoir is put into development and identification after the carbonate low-porosity and low-permeability reservoir is put into development.

[0086] Identifying before the carbonate low-porosity and low-permeability reservoir is put into development means identifying potential reservoir damage factors existing in the carbonate low-porosity and low-permeability reservoir based on initial reservoir and fluid parameters, and discriminating the sensitivity degree.

[0087] Identifying after the carbonate low-porosity and low-permeability reservoir is put into development means identifying the liquid loading and blockage conditions in the wellbore based on gas well monitoring data, judging whether liquid loading and scale blockage occur in the wellbore. If so, construction is required to remove them; and identifying the degree of water lock in the reservoir based on gas well monitoring data, gas reservoir reservoir and fluid parameters, and obtaining the range of water lock damage.

[0088] Among them, the method for judging whether liquid loading and scale blockage occur in the wellbore includes the following steps:

[0089] S 21 . According to the gas production rate, water production rate, tubing inner diameter, gas-water density and tubing wellhead pressure of the gas well, by dividing the wellbore into a series of well sections, iteratively calculating the pressure drop of each well section from the wellhead oil pressure, calculating the multiphase flow in the wellbore using the Hagedron-Brown model, and calculating the theoretical bottom-hole flowing pressure under normal production conditions of the gas well:

[0090]

[0091] ρ m =ρ1H1 + ρ g (1 - H1)

[0092] G m =G g +G1 = A(v sl ρ l +v sg ρ g )

[0093] In the formula: ρ is the fluid density; H l is the liquid holdup; A is the tubing flow cross-sectional area; D is the tubing inner diameter; G is the fluid mass flow rate, and v is the fluid volume flow rate;

[0094] S 22 . According to the theoretical bottom-hole flowing pressure and the static gas column pressure in the tubing-casing annulus, calculate the theoretical casing wellhead pressure:

[0095]

[0096] In the formula: P c is the theoretical casing wellhead pressure; P wf is the theoretical bottom-hole flowing pressure; γ is the gas relative density; H is the mid-depth of the gas reservoir; T is the average wellbore temperature; Z is the average gas deviation factor in the wellbore;

[0097] S 23. Calculate the critical liquid-carrying gas volume of a gas well using the Turner model based on the gas-water interfacial tension and gas-water density:

[0098]

[0099] Where: v cr is the critical liquid-carrying gas volume of the gas well; k s is the safety factor; C d is the drag coefficient; ρ g , ρ l are the densities of the gas and water;

[0100] S 24 . Compare the actual gas production volume and the wellhead pressure of the oil casing with the critical liquid-carrying gas volume and the theoretical oil-casing pressure difference to determine the liquid accumulation and scaling blockage conditions in the wellbore:

[0101] 1) If the actual gas production volume is lower than the critical liquid-carrying gas volume and the actual oil-casing pressure difference exceeds the theoretical oil-casing pressure difference, there may be liquid accumulation in the wellbore;

[0102] 2) If the actual gas production volume exceeds the critical liquid-carrying gas volume and the actual oil-casing pressure difference exceeds the theoretical oil-casing pressure difference, there may be blockage in the wellbore.

[0103] Among them, the method for identifying the degree of water lock in the reservoir includes the following steps:

[0104] S 31 . Obtain the production dynamic data of carbonate rock low-porosity and low-permeability reservoirs, fluids, and gas wells;

[0105] S 32 . Establish a gas well productivity equation considering the effect of water lock according to the steady-state gas flow condition considering the effect of water lock:

[0106]

[0107]

[0108]

[0109] S = S′ + S b

[0110]

[0111] Where: P e is the formation pressure of the gas reservoir; r e is the drainage radius; h is the effective thickness of the gas reservoir; q sc is the gas well production; K is the original permeability of the gas reservoir; S’ is the skin factor of reservoir damage caused by factors other than water lock; Z is the gas deviation factor; ra is the water lock radius; K ais the permeability after water lock; S b is the skin factor caused by water lock;

[0112] S 33 . According to the equation in step S 32 , use the Newton iteration method to iterate and solve the equation to obtain the water lock radius and identify the water lock range of the reservoir:

[0113] f(r a ) = 0

[0114]

[0115]

[0116] In the formula: f represents the gas well productivity equation considering the influence of water lock; the subscripts n and n + 1 represent the Newton iteration levels.

[0117] Example 4

[0118] As the best implementation mode of the present invention, the present invention includes a comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs, including identification before the development of carbonate rock low-porosity and low-permeability reservoirs and identification after the development of carbonate rock low-porosity and low-permeability reservoirs. Among them, the identification before the development of carbonate rock low-porosity and low-permeability reservoirs and the identification after the development of carbonate rock low-porosity and low-permeability reservoirs are two relatively independent processes. Before the development of carbonate rock low-porosity and low-permeability reservoirs, potential damage evaluation can be carried out first. If it is found to be relatively strongly sensitive, attention needs to be paid during the subsequent construction process, such as adding treatment agents to minimize the sensitivity impact, providing certain guidance for the subsequent construction; when the development starts, the current damage situation of the reservoir can be judged in real time according to the productivity, providing a basis for the reservoir plugging removal construction.

[0119] Among them, the identification before the development of carbonate rock low-porosity and low-permeability reservoirs specifically includes the following steps:

[0120] S1. Identify the potential reservoir damage factors existing in the carbonate rock low-porosity and low-permeability reservoir based on the initial reservoir and fluid parameters, and judge the sensitivity degree. More specifically, it includes the following steps:

[0121] S 11 . Obtain the reservoir and fluid parameters for the carbonate rock low-porosity and low-permeability reservoir. The reservoir and fluid parameters include reservoir gas permeability, porosity, initial water saturation, gas-water interfacial tension, contact angle, gas viscosity, water phase viscosity, water-gas viscosity ratio, irreducible water saturation, and invasion depth.

[0122] S 12. Calculate the water-phase trapping index values of the reservoir based on reservoir and fluid parameters. The water-phase trapping index values include the aqueous-phase trapping index APT, the aqueous-phase trapping factor PTC, and the aqueous-phase trapping index CAPT applicable to gas reservoirs. Among them, the calculation method of the aqueous-phase trapping index APT is as follows:

[0123] APT = 0.25lgk + 2.2S wi

[0124] The calculation method of the aqueous-phase trapping factor PTC is as follows:

[0125]

[0126] The calculation method of the aqueous-phase trapping index CAPT applicable to gas reservoirs is as follows:

[0127]

[0128] In the formula: k is the gas permeability of the reservoir; S wi is the initial water saturation of the reservoir; is the porosity; σ is the gas-water interfacial tension; θ is the contact angle; μm is the water-gas viscosity ratio; △p is the maximum pressure difference provided by the oil and gas reservoir during fluid discharge; S wirr is the irreducible water saturation of the reservoir; μ g is the gas viscosity; μ w is the water-phase viscosity; I d is the invasion depth.

[0129] S 13 . Based on the calculated water-phase trapping index values, determine the sensitivity of potential water-phase trapping in carbonate reservoirs with low porosity and low permeability, and take the maximum value of the determined results, that is, use the maximum sensitivity result judged as the sensitivity of water-phase trapping damage.

[0130] Among them, when determining the aqueous-phase trapping index APT, the determination criteria are as follows:

[0131] APT value range Water lock damage sensitivity <![CDATA[APT i ≥1.0]]> Insensitive <![CDATA[0.8 ≤ APT i ≤ 1.0]]> Relatively sensitive <![CDATA[APT i ≤0.8]]> Very sensitive

[0132] When determining the aqueous-phase trapping factor PTC, the determination criteria are as follows:

[0133]

[0134] When determining the aqueous-phase trapping index CAPT applicable to gas reservoirs, the determination criteria are as follows:

[0135] Among them, after the carbonate reservoirs with low porosity and low permeability are put into development, the identification is carried out, which specifically includes the following steps:

[0136] S2. Identify the liquid accumulation and blockage conditions in the wellbore based on the gas well monitoring data, and determine whether there is liquid accumulation and scale blockage in the wellbore. If so, perform construction to remove the liquid accumulation and blockage in the wellbore. After removal, enter step S3. If not, directly enter step S3. At present, there are various factors for the decline in gas well production, which may be liquid accumulation and scale formation in the wellbore or water lock in the reservoir. Before judging and calculating the water lock in the reservoir, it is necessary to exclude the liquid accumulation and scale formation in the wellbore, otherwise it will affect the accuracy of water lock identification in the reservoir.

[0137] In step S2, the method for judging whether there is liquid accumulation and scale blockage in the wellbore includes the following steps:

[0138] S 21 . According to the gas production, water production, inner diameter of the tubing, gas-water density, and tubing wellhead pressure of the gas well, by dividing the wellbore into a series of well sections, iteratively calculate the pressure drop of each well section from the wellhead oil pressure, and use the Hagedron-Brown model to calculate the multiphase flow in the wellbore, and calculate the theoretical bottomhole flowing pressure under normal production conditions of the gas well:

[0139]

[0140] ρ m = ρ1H1 + ρ g (1 - H1)

[0141] G m = G g + G1 = A(v sl ρ l + v sg ρ g )

[0142] In the formula: ρ is the fluid density; H l is the liquid holdup; A is the cross-sectional area of the tubing flow; D is the inner diameter of the tubing; G is the fluid mass flow rate, and v is the fluid volume flow rate;

[0143] S 22 . Calculate the theoretical casing wellhead pressure based on the theoretical bottomhole flowing pressure and the static gas column pressure in the tubing-casing annulus:

[0144]

[0145] In the formula: P c is the theoretical casing wellhead pressure; P wf is the theoretical bottomhole flowing pressure; γ is the relative density of the gas; H is the depth of the middle of the gas layer; T is the average temperature of the wellbore; Z is the average deviation factor of the gas in the wellbore;

[0146] S 23 . Calculate the critical liquid-carrying gas volume of the gas well using the Turner model based on the gas-water interfacial tension and gas-water density:

[0147] The calculation method for the critical liquid-carrying gas volume of the gas well is as follows:

[0148]

[0149] In the formula: v cr is the critical liquid-carrying gas volume of the gas well; k s is the safety factor; C d is the drag coefficient; ρ g and ρ l are the densities of the gas and water;

[0150] S 24 . Based on the actual gas production volume of the gas well and the wellhead pressures of the tubing and casing, compare with the critical liquid-carrying gas volume and the theoretical tubing-casing pressure difference to determine the wellbore liquid accumulation and scaling blockage conditions:

[0151] 1) If the actual gas production volume is lower than the critical liquid-carrying gas volume and the actual tubing-casing pressure difference exceeds the theoretical tubing-casing pressure difference, there may be liquid accumulation in the wellbore;

[0152] 2) If the actual gas production volume exceeds the critical liquid-carrying gas volume and the actual tubing-casing pressure difference exceeds the theoretical tubing-casing pressure difference, there may be blockage in the wellbore.

[0153] S3. Identify the degree of water blockage of the reservoir based on the gas well monitoring data, gas reservoir reservoir and fluid parameters, and obtain the range of water blockage damage. Specifically, it includes the following steps:

[0154] S 31 . Obtain the carbonate rock low-porosity and low-permeability reservoir, fluid, and gas well production dynamic data, including the gas reservoir formation pressure, supply radius, effective thickness of the gas reservoir, gas production volume of the gas well, original permeability of the gas reservoir, permeability after water blockage, reservoir damage skin factor, and gas deviation factor.

[0155] S 32 . According to the gas steady flow state considering the influence of water blockage, establish a gas well productivity equation considering the influence of water blockage:

[0156]

[0157]

[0158]

[0159] S = S′ + S b

[0160]

[0161] In the formula: P e is the gas reservoir formation pressure; r eis the drainage radius; h is the effective thickness of the gas reservoir; q sc is the gas well production rate; K is the original permeability of the gas reservoir; S’ is the skin factor of reservoir damage caused by factors other than water blockage; Z is the gas deviation factor; ra is the water blockage radius; K a is the permeability after water blockage; S b is the skin factor caused by water blockage.

[0162] S 33 . According to the equation in step S 32 , use the Newton iteration method to iterate and solve the equation to obtain the water blockage radius and identify the reservoir water blockage range:

[0163] f(r a ) = 0

[0164]

[0165]

[0166] In the formula: f represents the gas well productivity equation considering the influence of water blockage; the subscripts n and n + 1 represent the Newton iteration levels. Given the initial guessed value of the water blockage radius, the true water blockage radius can be calculated through multiple Newton iterations.

[0167] Example 5

[0168] Use the comprehensive identification method in Example 4 for case analysis as follows:

[0169] Reservoir and fluid parameters before development: The gas permeability of the reservoir is 10 mD, the initial water saturation of the reservoir is 10%, the porosity is 12%, the interfacial tension is 20 mN / m, the contact angle is 45°, the viscosity ratio of the invading phase to the reservoir gas is 50, the maximum pressure difference provided by the oil and gas reservoir during fluid drainage is 1 MPa, the irreducible water saturation of the reservoir is 5%, the gas viscosity is 0.02 mPa·s, and the liquid phase viscosity is 1 mPa·s. The calculated result of potential damage is strongly sensitive.

[0170] Wellbore liquid holdup and plugging parameters after development: The safety factor is 1.2, the interfacial tension is 0.02 N / m, the liquid phase density is 1000 kg / m 3 , the gas phase density is 0.7 kg / m 3 , the drag coefficient is 0.43, the bottom hole flowing pressure is 10 MPa, the relative density of natural gas is 0.55, the well depth in the middle of the gas layer is 1500 m, the average wellbore temperature is 323 K, the average gas deviation factor is 1.02, the actual gas production is 10,000 m³ / day, and the actual tubing - casing pressure difference is 1 MPa. The calculated result is wellbore liquid holdup and wellbore plugging.

[0171] Developed liquid-phase trap damage parameters: formation pressure is 10 MPa, effective thickness of the gas reservoir is 5 m, formation temperature is 343 K, supply radius is 100 m, bottom-hole radius is 0.05 m, permeability after water-lock damage is 1 mD, gas well production is 10,000 m³ / day, skin factor of reservoir damage except water-lock is 0.1, original permeability of the gas reservoir is 10 mD, gas viscosity is 0.02, bottom-hole flowing pressure is 12 MPa, relative density of natural gas is 0.55, average deviation factor of gas is 1.02. The calculated result of the liquid-phase trap damage radius is 1.05 m.

[0172] Example 6

[0173] Using the comprehensive identification method in Example 4, case analysis is carried out as follows:

[0174] Reservoir and fluid parameters before development: gas permeability of the reservoir is 100 mD, initial water saturation of the reservoir is 10%, porosity is 20%, interfacial tension is 15 mN / m, contact angle is 65°, ratio of viscosity of the invading phase to the viscosity of the reservoir gas is 50, maximum pressure difference provided by the oil and gas reservoir during fluid drainage is 5 MPa, irreducible water saturation of the reservoir is 5%, gas viscosity is 0.02 mPa·s, liquid-phase viscosity is 1 mPa·s. The calculated result of potential damage is no sensitivity.

[0175] Wellbore liquid accumulation and blockage parameters after development: safety factor is 1.3, interfacial tension is 0.01 N / m, liquid-phase density is 1000 kg / m 3 and gas-phase density is 0.7 kg / m 3 , drag coefficient is 0.43, bottom-hole flowing pressure is 20 MPa, relative density of natural gas is 0.55, well depth at the middle of the gas layer is 3000 m, average wellbore temperature is 393 K, average deviation factor of gas is 1.02, actual gas production is 50,000 m³ / day, actual tubing-casing pressure difference is 0.1 MPa. The calculated result is no wellbore liquid accumulation and no wellbore blockage.

[0176] Developed liquid-phase trap damage parameters: formation pressure is 20 MPa, effective thickness of the gas reservoir is 15 m, formation temperature is 393 K, supply radius is 150 m, bottom-hole radius is 0.05 m, permeability after water-lock damage is 50 mD, gas well production is 50,000 m³ / day, skin factor of reservoir damage except water-lock is 0, original permeability of the gas reservoir is 1000 mD, gas viscosity is 0.02, bottom-hole flowing pressure is 25 MPa, relative density of natural gas is 0.55, average deviation factor of gas is 1.02. The calculated result of the liquid-phase trap damage radius is 0.5 m.

[0177] In summary, after those of ordinary skill in the art read the documents of the present invention, all other corresponding transformation schemes made without creative mental labor according to the technical solutions and technical concepts of the present invention fall within the scope protected by the present invention.

Claims

1. A comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs, characterized in that: It includes identification before the carbonate low-porosity and low-permeability reservoir is put into development and identification after the carbonate low-porosity and low-permeability reservoir is put into development; Among them, the identification before the carbonate low-porosity and low-permeability reservoir is put into development specifically includes the following steps: S1. Based on the initial reservoir and fluid parameters, calculate the water-phase trapping index value of the reservoir. The water-phase trapping index value includes the water-phase trapping index CAPT applicable to gas reservoirs; identify the potential reservoir damage factors existing in the carbonate low-porosity and low-permeability reservoir according to the water-phase trapping index value, and judge the sensitivity degree; The calculation method of the water-phase trapping index CAPT applicable to gas reservoirs is: Where: k is the gas permeability of the reservoir; S wi is the initial water saturation of the reservoir; φ is the porosity; σ is the gas-water interfacial tension; θ is the contact angle; △p is the maximum pressure difference provided by the oil and gas reservoir during fluid drainage; S wirr is the irreducible water saturation of the reservoir; μ g is the gas viscosity; μ w is the water-phase viscosity; I d is the invasion depth; Among them, the identification after the carbonate low-porosity and low-permeability reservoir is put into development specifically includes the following steps: S2. Identify the liquid loading and blockage conditions in the wellbore based on the gas well monitoring data, judge whether there is liquid loading and scale blockage in the wellbore. If so, perform construction to remove the liquid loading and blockage in the wellbore. After removal, enter step S3. If not, directly enter step S3; S3. Identify the water lock degree of the reservoir based on the gas well monitoring data, gas reservoir and fluid parameters, and obtain the water lock damage range, specifically including the following steps: S 31 . Obtain the production dynamic data of carbonate rock reservoirs with low porosity and low permeability, fluids, and gas wells; S 32 . Establish a gas well productivity equation considering the effect of water block according to the steady gas flow state considering the effect of water block: S = S′ + S b Where: P e is the formation pressure of the gas reservoir; r e is the drainage radius; h is the effective thickness of the gas reservoir; q sc is the gas well production; K is the original permeability of the gas reservoir; S′ is the skin factor of reservoir damage caused by factors other than water lock; Z is the gas deviation factor; r a is the water lock radius; K a is the permeability after water lock; S b is the skin factor caused by water lock; S 33 . According to the equation in step S 32 , use the Newton iteration method to iterate and solve the equation to obtain the water lock radius and identify the range of reservoir water lock damage: f(r a )＝0 In the formula: f represents the gas well productivity equation considering the influence of water lock; the subscripts n and n + 1 represent the Newton iteration levels.

2. The comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs according to claim 1, characterized in that: Step S1 specifically includes the following steps: S 11 . Obtain reservoir and fluid parameters for carbonate low-porosity and low-permeability reservoirs; S 12 . Calculate the water-phase trapping index values of the reservoir according to reservoir and fluid parameters, where the water-phase trapping index values include the aqueous phase trapping index APT, the aqueous phase trapping factor PTC, and the aqueous phase trapping index CAPT applicable to gas reservoirs; S 13 . Discriminate the sensitivity of potential water-phase trapping in carbonate reservoirs with low porosity and low permeability according to the calculated water-phase trapping index values.

3. The comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs according to claim 2, wherein: The reservoir and fluid parameters include reservoir gas logging permeability, porosity, initial water saturation, gas-water interfacial tension, contact angle, gas viscosity, water-phase viscosity, water-gas viscosity ratio, irreducible water saturation, and invasion depth.

4. The comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs according to claim 3, characterized in that: The calculation method of the water-phase trapping index APT is: APT = 0.25lgk + 2.2S wi The calculation method of the water-phase trapping factor PTC is: Where: k is the gas permeability of the reservoir; S wi is the initial water saturation of the reservoir; φ is the porosity; σ is the gas-water interfacial tension; θ is the contact angle; μ m is the water-gas viscosity ratio; △p is the maximum pressure difference provided by the oil and gas reservoir during fluid drainage; S wirr is the irreducible water saturation of the reservoir.

5. The comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs according to claim 2 or 4, characterized in that: The said step S 13 Specifically, it means to respectively determine the aqueous phase trapping index APT, the aqueous phase trapping factor PTC, and the aqueous phase trapping index CAPT applicable to gas reservoirs, and take the maximum value of the determined results as the sensitivity of aqueous phase trapping damage.

6. The comprehensive identification method for the damage degree of carbonate low-porosity and low-permeability reservoirs according to claim 5, characterized in that: The specific discrimination of the aqueous phase trapping index APT means that if APT i ≥ 1.0, it is judged that the water lock damage is insensitive; if 0.8 ≤ APT i ≤ 1.0, it is judged that the water lock damage is relatively sensitive. If APT i ≤ 0.8, it is judged that the water lock damage is very sensitive; The discrimination of the water-phase trapping factor PTC specifically means: if PTC < 0.05, it is judged as insensitive; if 0.05 ≤ PTC < 0.3, it is judged as weakly sensitive; if 0.3 ≤ PTC < 0.5, it is judged as weakly to moderately sensitive; if 0.5 ≤ PTC < 0.7, it is judged as moderately to strongly sensitive; if PTC ≥ 0.7, it is judged as strongly sensitive; the discrimination of the water-phase trapping index CAPT applicable to gas reservoirs specifically means: if CAPT < 0.05, it is judged as insensitive; if 0.05 ≤ CAPT < 0.3, it is judged as weakly sensitive; if 0.3 ≤ CAPT < 0.5, it is judged as weakly to moderately sensitive; if 0.5 ≤ CAPT < 0.7, it is judged as moderately to strongly sensitive; if CAPT ≥ 0.7, it is judged as strongly sensitive.

7. The comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs according to claim 1 or 6, characterized in that: The judgment method for whether there is liquid loading and scale blockage in the wellbore includes the following steps: S 21 . Based on the gas production volume, water production volume, inner diameter of the tubing, gas-water density, and tubing wellhead pressure of the gas well, by dividing the wellbore into a series of well sections, iteratively calculating the pressure drop of each well section from the wellhead oil pressure, and using the Hagedron-Brown model to calculate the multiphase flow in the wellbore, calculate the theoretical bottom-hole flowing pressure under normal production conditions of the gas well; S 22 . Calculate the theoretical casing wellhead pressure based on the theoretical bottom-hole flowing pressure and the static gas column pressure in the annulus between the casing and tubing. S 23 . Calculate the critical liquid-carrying gas volume of gas wells using the Turner model based on the gas-water interfacial tension and gas-water density; S 24 . Based on the actual gas production rate of the gas well and the wellhead pressure of the oil casing, compare with the critical liquid-carrying gas volume and the theoretical oil-casing pressure difference to determine the liquid accumulation and scale blockage conditions in the wellbore: 1) If the actual gas production is lower than the critical liquid-carrying gas volume and the actual tubing-casing pressure difference exceeds the theoretical tubing-casing pressure difference, there may be liquid loading in the wellbore; 2) If the actual gas production exceeds the critical liquid-carrying gas volume and the actual tubing-casing pressure difference exceeds the theoretical tubing-casing pressure difference, there may be blockage in the wellbore.

8. The comprehensive identification method for the damage degree of a carbonate rock low-porosity and low-permeability reservoir according to claim 7, characterized in that: The calculation method of the theoretical bottom-hole flowing pressure under normal production conditions of the gas well is: ρ m = ρ l H l + ρ g (1 - H l ) G m = G g + G l = A(v sl ρ l + v sg ρ g ) Where: ρ is the fluid density; H l is the liquid holdup; A is the flow cross-sectional area of the tubing; D is the inner diameter of the tubing; G is the mass flow rate of the fluid, and v is the volume flow rate of the fluid; The calculation method of the theoretical casing wellhead pressure is: Where: P c is the theoretical casing wellhead pressure; P wf is the theoretical bottom-hole flowing pressure; γ g is the relative density of gas; H is the mid-depth of the gas reservoir; T is the average temperature of the wellbore; Z is the average gas deviation factor in the wellbore; The calculation method of the critical liquid-carrying gas volume of the gas well is: Where: v cr is the critical liquid-carrying gas volume of the gas well; k s is the safety factor; C d is the drag coefficient; ρ g , ρ l are the densities of the gas and water.

9. The comprehensive identification method for the damage degree of carbonate rock low-porosity and low-permeability reservoirs according to claim 1, wherein: The production dynamic data includes gas reservoir formation pressure, supply radius, effective thickness of the gas reservoir, gas production rate of the gas well, original permeability of the gas reservoir, permeability after water block, skin factor of reservoir damage, and gas deviation factor.

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