A temporary plugging and acidification design method using temperature-responsive temporary plugging agent

Abstract

The present invention discloses a temporary plugging acidification design method using a temperature-responsive temporary plugging agent, the specific steps of which include: (1) obtaining basic data and determining the number of staged acidification sections; (2) optimizing the acid solution system and construction process; (3) calculating the acid solution dosage and the wellbore-formation temperature field, and selecting a temperature-responsive liquid gelling temporary plugging agent; (4) calculating the temporary plugging agent dosage and determining the gelling reaction kinetic equation; (5) calculating the wellbore-formation temperature field and optimizing the design construction parameters; (6) repeating steps S3 to S5 to design the acidification construction parameters for each section. The design method proposed by the present invention is systematic and comprehensive, with strong operability; considering the influence of multiple factors, the calculation results are more accurate; and since all liquid is injected, the construction difficulty is low.

Description

Technical Field

[0001] The invention relates to an acidizing production-increasing technology in the process of oil and gas field development, in particular to a temporary plugging acidizing design method using a temperature-responsive temporary plugging agent, and belongs to the field of oil and gas field production-increasing transformation. Background Art

[0002] To improve economic efficiency, many oil and gas wells are developed using multi-layer commingled production or single-layer long well sections. In these situations, reservoir heterogeneity issues are leading to increasingly prominent production reductions. Furthermore, to address issues such as reservoir sand production and wellbore instability, screen completions are widely used in offshore and some onshore oil and gas fields. Compared to hydraulic fracturing and acid fracturing, matrix acidizing (abbreviated as acidizing) is a production-enhancing technology with advantages such as reduced risk, reduced space usage, and low construction costs, leading to its widespread adoption. To address the issues caused by reservoir heterogeneity, temporary plugging agents (also known as diverters and diverters) are used in acidizing to achieve uniform acidization throughout the entire well section. However, due to the high sand retention accuracy of screens, solid temporary plugging agents such as chemical particles and fibers have difficulty passing through the screens and entering the reservoir, limiting their use. Therefore, liquid viscosifying and liquid gelling temporary plugging agents have become the preferred solution. Liquid viscosity-changing temporary plugging agents are mostly viscoelastic surfactants that become viscous by forming micelles, but for reservoirs with strong heterogeneity (meaning a large permeability range), the viscosity-changing temporary plugging agent is extremely unsatisfactory. Therefore, liquid gel-forming temporary plugging agents are used. In recent years, a variety of temperature-responsive liquid gel-forming temporary plugging agents have been developed, such as a temperature-responsive microgel disclosed in CN110283579B, a temperature-responsive self-degradable temporary plugging agent disclosed in CN113185960B and CN113185656B, a temperature-responsive hydrogel disclosed in CN111187607A, a smart diverter disclosed in CN111269703A, a thermo-induced supramolecular gel disclosed in CN106190087B, etc. However, due to the lack of a temporary plugging acidification design method for temperature-responsive liquid gel-forming temporary plugging agents, the construction success rate is unsatisfactory, and its large-scale promotion and application is also limited. Summary of the Invention

[0003] The purpose of the present invention is to address the above-mentioned shortcomings and propose a temporary plugging acidification design method using a temperature-responsive temporary plugging agent. The specific technical solution is as follows.

[0004] Step S1: Obtain wellbore structure and wellbore trajectory data, thermophysical parameters and temperature gradient data of each formation layer, and porosity, permeability, and skin coefficient distribution data along the wellbore in the pay zone to determine the number of staged acidizing sections n. The specific calculation is as follows (Xue Heng. Numerical Simulation of High-Efficiency Acidizing of Horizontal Wells in Complex Carbonate Reservoirs [D]. Southwest Petroleum University, 2017. Li Yingchuan. Oil Production Engineering, Second Edition [M]. Beijing: Petroleum Industry Press, 2008.):

[0005]

[0006] Where: J——production index, m 3 / (d·Pa); n——number of segmented acidification stages, dimensionless; K i ——Acidification permeability of section i, D; h i —— length of acid treatment single section, m; μ—— viscosity of reservoir fluid, Pa·s; r e ——discharge radius, m; r w ——Wellbore radius, m; K d,i ——Permeability of the pollution zone in section i, D; r i ——Acidizing radius, m. With J optimal as the goal, optimize the number of segmented acidizing sections n.

[0007] Step S2: Select the main acid type according to the reservoir lithology, determine the acid injection process according to the selected main acid type, and select the main acid system according to the construction purpose. Specifically: if the reservoir is sandstone, the main acid type should be a fluorine-containing acid system; if it is carbonate rock, the main acid type should be a non-fluorine-containing acid system; if the main acid type is a fluorine-containing acid system, a hydrochloric acid injection process should be added before and after the injection of the main acid to create an acidic environment and avoid secondary precipitation damage to the reservoir; if the construction purpose requires deep penetration of the acid, the main acid system should be a slow-speed acid system, and commonly used slow-speed acid systems include autogenous acid, fluoroboric acid, polyhydrogen acid, etc.; if the construction purpose requires high dissolution, the main acid system should be a soil acid or hydrochloric acid system.

[0008] Step S3: Calculate the acid dosage and the wellbore-formation temperature field considering the acid-rock reaction heat, select a temperature-responsive liquid gelling temporary plugging agent, and require the bottom hole temperature T bottom Less than but close to the gelling temperature T of temperature-responsive liquid gelling temporary plugging agent gel , and the original formation temperature of the treatment layer is T origin Greater than the gel breaking temperature T of the temperature-responsive liquid gelling temporary plugging agent break .

[0009] The specific calculation of acid dosage is as follows (Zhang Fengchao. Research on autogenous acid system for acidizing oil wells in offshore oil fields [D]. Southwest Petroleum University, 2019.), the main acid dosage Q m The calculation formula is:

[0010]

[0011] Where: Q m ——Main acid consumption, m 3 ;φ——porosity, decimal; N Da ——DamKahler number, dimensionless; N AC——Acid capacity, dimensionless.

[0012] If the main acid solution is a fluorine-containing acid system, the amount of pre-hydrochloric acid solution Q needs to be designed. pre And the amount of post-hydrochloric acid solution Q later , pre-hydrochloric acid solution dosage Q pre The calculation formula is:

[0013]

[0014] Where: Q pre ——Pre-treatment hydrochloric acid solution dosage, m 3 ; C HCl ——Percentage of hydrochloric acid soluble matter, decimal; X HCl ——The solubility of hydrochloric acid, dimensionless; ζ1——empirical coefficient, generally greater than 1.

[0015] Post-hydrochloric acid solution dosage Q later The calculation formula is:

[0016]

[0017] Where: Q later ——Amount of post-treatment hydrochloric acid solution, m 3 ; r m ——displacement radius (recommended to be greater than 0.5m), m; ζ2——empirical coefficient, generally greater than 1.

[0018] The specific calculation of the wellbore-formation temperature field considering the heat of acid-rock reaction is as follows. The calculation formula of the wellbore temperature field is (Xian Chao. Simulation study of temperature field of autogenous solid-phase chemical fracturing [D]. Southwest Petroleum University, 2018.)

[0019]

[0020] Where: q j ——Flow rate at unit j in the wellbore, m 3 / s;T j,flu ——Fluid temperature at unit j in the wellbore, K; x——wellbore trajectory direction, m; r j ——Inner radius of the pipe at unit j in the wellbore, m; α j ——Convection heat transfer coefficient between the fluid and the pipe wall at unit j in the wellbore, W / (m 2 ·K); T j,c / s ——the wall temperature at unit j in the wellbore, K; ρ j ——Fluid density at unit j in the wellbore, kg / m 3 ; C j ——Specific heat capacity of the fluid at unit j in the wellbore, J / (kg·K); j ——friction coefficient at unit j in the wellbore; uj ——flow velocity at unit j in the wellbore, m / s; t——time, s.

[0021] The calculation formula of the formation temperature field is (Xue Heng. Numerical simulation study on efficient acidizing of horizontal wells in complex carbonate reservoirs [D]. Southwest Petroleum University, 2017.)

[0022]

[0023] Where: ρ s ——Rock density, kg / m 3 ; C Ps ——Specific heat capacity of rock, J / (kg K); T s ——rock temperature, K; ρ f ——Fluid density, kg / m 3 ; C Pf ——Specific heat capacity of fluid, J / (kg K); T f ——fluid temperature, K; U——flow velocity, m / s; k ef ——Fluid thermal conductivity, W( / m·K); k es ——Thermal conductivity of rock, W / (m·K); △H r ——Acid-rock reaction enthalpy, J / mol; a v ——pore specific surface area, m 2 / m 3 ;k c ——Mass transfer rate, m / s; C f ——Mass concentration of acid in pores, mol / m 3 ; C s ——Acid concentration at the pore wall, mol / m 3 .

[0024] Deterministic conditions: Initially, the temperature distribution in the wellbore is consistent with the formation temperature, and the formation temperature is the original formation temperature; the wellhead temperature is the actual temperature of the injected fluid, and the formation adopts a constant temperature boundary condition.

[0025] Step S4: Calculate the dosage of the temperature-responsive liquid gelling temporary plugging agent and determine the gelling reaction kinetic equation. div The calculation formula is:

[0026]

[0027] Where: Q div ——Dosage of temperature-responsive liquid gelling temporary plugging agent, m 3 ;ζ3——empirical coefficient, generally greater than 1;P n ——temporary plugging strength, MPa; P b——Breakthrough pressure gradient, MPa / m.

[0028] Method for determining the kinetic equation of gelation reaction (Zhang Nanlin. Key theoretical research on phase change self-supporting fracturing [D]. Southwest Petroleum University, 2022; Wang Yanping. Synthesis of modified fatty amine and its curing reaction research on epoxy resin [D]. Henan University, 2015; Wang Linhao, Luo Yongming, et al. Study on the curing reaction kinetics of liquid polycarbosilane [J]. Polymer Bulletin, 2016, (09): 149-155; Malek J. The kinetic analysis of non-isothermal data [J]. Thermochimica Acta, 1992, 200(8): 257-269.): The temperature-responsive liquid gelling temporary plugging agent was subjected to non-isothermal differential scanning calorimetry (DSC) tests at different heating rates. The preferred heating rates were 2.5, 5.0, 7.5, 10.0, 12.5, 15.0, 17.5, 20.0, 22.5, 25.0, 27.5 or 30.0 K / min, and at least three heating rates were selected. The heat ΔH and gelling rate dα / dt were obtained by simple processing of the DSC test results. The integral method Flynn-Wall-Ozawa method and the differential method Kissinger method were used. -Akahira-Sunose method is used to calculate the pre-exponential factor A and activation energy E. The results obtained by the two methods are averaged, and the kinetic index n is calculated using the Crane equation; the DSC test results are substituted into formula (8) to draw the experimental curve of y(α)~α; the commonly used kinetic mechanism function f(α) (corresponding to function numbers 1 to 45) is substituted into formula (9) to draw the standard curve of y(α)~α; the standard curve is plotted together with the experimental curve, and the experimental curve is compared to see which standard curve has the highest degree of overlap. The kinetic mechanism function f(α) corresponding to the highest degree of overlap is selected and substituted into formula (10) to obtain the kinetic equation of the gelation reaction.

[0029]

[0030] y(α)=Af(α) (9)

[0031]

[0032] Where: y(α)——definition function; E——activation energy, J / mol; R——molar gas constant, J / (mol·K); T——temperature, K; α——gelation rate, decimal; A——pre-exponential factor, s -1 ; f(α)——kinetic mechanism function; dα / dt——gelation rate, s -1 .

[0033] Step S5: Calculate the wellbore-formation temperature field taking into account the gelling reaction heat of the temperature-responsive liquid gelling temporary plugging agent and the acid-rock reaction heat, and optimize the design of construction parameters.

[0034] The wellbore-formation temperature field is specifically calculated considering the gelling reaction heat of the temperature-responsive liquid gelling temporary plugging agent and the acid-rock reaction heat. The calculation formula for the wellbore temperature field is:

[0035]

[0036] Where: ΔH - heat (exothermic is positive, endothermic is negative), J / kg; V j ——The volume of unit j in the wellbore, m 3 .

[0037] The calculation formula of the formation temperature field is:

[0038]

[0039] By changing the injection displacement q j The temperature field distribution can be regulated by the injection time t, so that the temperature-responsive liquid gelling temporary plugging agent will not gel in the wellbore, but can gel in the formation as quickly as possible to achieve temporary plugging, ultimately achieving the purpose of optimizing the design and construction parameters; the bottom hole pressure corresponding to the preferred injection displacement should not be greater than the formation fracture pressure.

[0040] Step S6: Repeat steps S3 to S5 to design the acidizing construction parameters for each section. When designing the last section, just repeat step 3.

[0041] In the above calculation method, the same symbols involved in all formulas have the same meaning before and after, and after being marked once, they are applicable to all formulas.

[0042] The present invention proposes a temporary plugging acidification design method using a temperature-responsive temporary plugging agent. Figure 1 shown.

[0043] The benefits of the present invention lie in: proposing a design method for achieving uniform acidification of heterogeneous reservoirs based on a temperature-responsive liquid gelling temporary plugging agent; the method is comprehensive and highly operable; during construction, all liquid is injected, which can smoothly pass through sand control completion tools such as screens and enter the reservoir; reaction heat, friction heat, heat conduction and heat convection are taken into account, and the temperature field calculation is more accurate.

[0044] Other advantages, objectives and features of the present invention will be reflected in part from the following description and will be understood by those skilled in the art through study and practice of the present invention. BRIEF DESCRIPTION OF THE DRAWINGS

[0045] Figure 1The flow chart of a temporary plugging and acidification design method using a temperature-responsive temporary plugging agent.

[0046] Figure 2 The distribution diagram of the physical properties of the pay zone along the horizontal wellbore.

[0047] Figure 3 This is the relationship curve between the number of segmented acidizing stages and the production index.

[0048] Figure 4 is the wellbore temperature distribution curve.

[0049] Figure 5 It is the formation temperature distribution profile.

[0050] Figure 6 This is the DSC test data. DETAILED DESCRIPTION

[0051] The preferred embodiments of the present invention are described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are only used to illustrate and explain the present invention, and are not used to limit the present invention.

[0052] Example

[0053] Taking the Y-5H well in the offshore BZ oilfield as an example, the lithology of the Y-5H well's pay layer is sandstone, the vertical depth of the middle part of the pay layer is 3650m, the horizontal section is 1250m long, and the well is completed with an open hole sand control screen. Due to the damage of the drilling fluid, the pay layer has a large positive skin coefficient, and temporary plugging and acidizing transformation is required.

[0054] Step S1: The porosity, permeability and skin coefficient distribution data along the wellbore in the production layer are as follows: Figure 2 As shown in the figure, the discharge radius is 600m, the wellbore radius is 0.07m, the average contaminated zone radius in the horizontal well section of 0-470m is 0.15m, and the average contaminated zone radius in the horizontal well section of 470-1250m is 0.36m. Successful acidizing and plugging removal requires breaking through the contaminated zone (i.e., the acidizing radius should not be less than the contaminated zone radius, and the acidizing radius can be set equal to the contaminated zone radius). Set up 5 segmentation schemes, Scheme 1: Whole well general acidization, that is, no segmentation; Scheme 2: Whole well divided into 2 segments acidization, divided into 0-470m and 470-1250m; Scheme 3: Whole well divided into 3 segments acidization, divided into 0-470m, 470-910m and 910-1250m; Scheme 4: Whole well divided into 4 segments acidization, divided into 0-470m, 470-780m, 780-950m and 950-1250m; Scheme 5: Whole well divided into 5 segments acidization, divided into 0-470m, 470-610m, 610-770m, 770-950m and 950-1250m. J under different schemes is calculated by formula (1), as follows: Figure 3 As shown, the more segments there are, the larger J is, but the corresponding construction operations are more complicated. Therefore, if the system is divided into 3 segments, Scheme 3 is the best, that is, n=3.

[0055] Step S2: The lithology is sandstone, and the main acid liquid type is a fluorine-containing acid liquid system. A hydrochloric acid injection process is added before and after the injection of the main acid. Since the reservoir properties are relatively good, the construction purpose requires high dissolution and decontamination, and the main acid liquid system is earth acid.

[0056] Section 1 (0~470m)

[0057] Step 3: DamKahler number 0.06, acid capacity 0.09, average porosity 0.16, acid treatment section length 470m, acidizing radius 0.15m, wellbore radius 0.07m, hydrochloric acid soluble matter ratio 0.12, hydrochloric acid solubility 0.08, ζ1 empirical coefficient 1.2, displacement radius 0.6m, ζ2 empirical coefficient 1.2. The main acid solution volume is calculated by formula (2) as 65.3m 3 , calculated by formula (3), the amount of pre-hydrochloric acid solution is 39.3m 3 , calculated by formula (4), the amount of post-hydrochloric acid solution is 100.6m 3 Wellbore trajectory: vertical section 0-2100m, deflection section 2100-4534m, horizontal section 4534-5784m. Tubing injection, injection rate 0.8m 3 / min. Oil pipe: inner diameter 0.38m, outer diameter 0.045m, density 7420kg / m 3 , specific heat capacity 470J / (kg·℃), thermal conductivity 49J / (m·℃·s). Injection fluid: viscosity 0.02Pa·s, density 1100kg / m 3 , specific heat capacity 3500J / (kg·℃), thermal conductivity 0.6J / (m·℃·s). Rock: density 2340kg / m 3 , specific heat capacity 285 J / (kg·℃), thermal conductivity 2.7 J / (m·℃·s). Ground temperature 18℃, geothermal gradient 3.4℃ / 100m, HCl concentration 15%, HF concentration 3%, acid-rock reaction enthalpy 13692 J / mol, pore specific surface area 3000m 2 / m 3 The wellbore temperature distribution is calculated by formula (5): Figure 4 As shown in the figure, the formation temperature distribution profile calculated by formula (6) is as follows: Figure 5 As shown in the figure, the bottomhole temperature is about 77°C, and the original formation temperature of the treated layer is about 142°C. Based on this, the PSA-2 temporary plugging agent disclosed in patent CN201610532563.4 was selected. Its initial gelling temperature is 90°C, the final gelling temperature is 95°C, the initial gel breaking temperature is 120°C, and the final gel breaking temperature is 125°C.

[0058] Step S4: Temporary plugging strength 2.5 MPa, breakthrough pressure gradient 29.3 MPa / m, ζ3 empirical coefficient 1.3, acid treatment single section length 470 m, wellbore radius 0.07 m, the temperature-responsive liquid gelling temporary plugging agent dosage is calculated as 36.9 m according to formula (7). 3 . DSC test data such as Figure 6 As shown, the calculated ΔH is 1.9 kJ / g and the pre-exponential factor is 2.7×10 12 , activation energy 90.2 kJ / mol and kinetic index 2.2, the kinetic mechanism function is obtained from formulas (8) and (9) as function number 2, which is substituted into formula (10) to obtain the following kinetic equation for the gelation reaction:

[0059]

[0060] Step S5: The wellbore temperature distribution can be calculated by formula (11), and the formation temperature distribution can be calculated by formula (12). By changing the injection displacement, the wellbore-formation temperature distribution under different displacements can be obtained; the larger the injection displacement, the lower the wellbore-formation temperature will be. Since gelation is an endothermic process, the wellbore-formation temperature obtained under the same displacement and injection time will be lower than Figure 4 and Figure 5 In order to prevent the temporary plugging agent from gelling in the wellbore but quickly gelling in the formation, the injection displacement was optimized to 0.4m 3 / min, and the corresponding bottom hole pressure at this displacement is lower than the fracture pressure of the production layer, and the corresponding bottom hole temperature is 83℃.

[0061] Step S6: Repeat steps S3 to S5, and similarly design the acidizing operation parameters for the second stage; repeat only step 3, and similarly design the acidizing operation parameters for the last stage (i.e., the third stage).

[0062] The above description is merely a preferred embodiment of the present invention and does not constitute any form of limitation to the present invention. Although the present invention has been disclosed as a preferred embodiment as above, it is not intended to limit the present invention. Any technician familiar with the present profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention are still within the scope of the technical solution of the present invention.

Claims

1. A temporary plugging acidification design method using a temperature-responsive temporary plugging agent, characterized in that: The following steps are involved: S1: Obtain wellbore structure and wellbore trajectory data, thermal physical parameters and temperature gradient data of each layer of the formation, porosity, permeability and skin coefficient distribution data along the wellbore in the pay zone, and determine the number of staged acidizing sections; S2: Select the main acid type according to the reservoir lithology, determine the acid injection process based on the selected main acid type, and select the main acid system according to the construction purpose; S3: Calculate the acid dosage and the wellbore-formation temperature field considering the acid-rock reaction heat, select a temperature-responsive liquid gelling temporary plugging agent, and require the bottom hole temperature T bottom Less than but close to the gelling temperature T of temperature-responsive liquid gelling temporary plugging agent gel , and the original formation temperature of the treatment layer is T origin Greater than the gel breaking temperature T of the temperature-responsive liquid gelling temporary plugging agent break ; S4: Calculate the dosage of temperature-responsive liquid gelling temporary plugging agent and determine the gelling reaction kinetic equation; the dosage of temperature-responsive liquid gelling temporary plugging agent Q div The calculation formula is: Where: Q div ——Dosage of temperature-responsive liquid gelling temporary plugging agent, m 3 ;h i —— length of single section of acid treatment, m; ζ3——empirical coefficient, generally greater than 1; P n ——temporary plugging strength, MPa; P b ——Breakthrough pressure gradient, MPa / m; r w ——Wellbore radius, m; S5: Calculate the wellbore-formation temperature field considering the gelling reaction heat of the temperature-responsive liquid gelling temporary plugging agent and the acid-rock reaction heat, and optimize the design of construction parameters. The wellbore-formation temperature field considering the gelling reaction heat of the temperature-responsive liquid gelling temporary plugging agent and the acid-rock reaction heat is specifically calculated as follows. The calculation formula for the wellbore temperature field is: Where: q j ——Flow rate at unit j in the wellbore, m 3 / s;T j,flu ——Fluid temperature at unit j in the wellbore, K; x——wellbore trajectory direction, m; r j ——Inner radius of the pipe at unit j in the wellbore, m; α j ——Convection heat transfer coefficient between the fluid and the pipe wall at unit j in the wellbore, W / (m 2 ·K); T j,c / s ——the wall temperature at unit j in the wellbore, K; ρ j ——Fluid density at unit j in the wellbore, kg / m 3 ; C j ——Specific heat capacity of the fluid at unit j in the wellbore, J / (kg·K); j ——friction coefficient at unit j in the wellbore; u j ——flow velocity at unit j in the wellbore, m / s; t——time, s; ΔH——heat (positive for heat release, negative for heat absorption), J / kg; V j ——The volume of unit j in the wellbore, m 3 ; The calculation formula of the formation temperature field is: Where: ρ s ——Rock density, kg / m 3 ; C Ps ——Specific heat capacity of rock, J / (kg K); T s ——rock temperature, K; ρ f ——Fluid density, kg / m 3 ; C Pf ——Specific heat capacity of fluid, J / (kg K); T f ——fluid temperature, K; U——flow velocity, m / s; φ——porosity, decimal; k ef ——Fluid thermal conductivity, W( / m·K); k es ——Thermal conductivity of rock, W / (m·K); △H r ——Acid-rock reaction enthalpy, J / mol; a v ——pore specific surface area, m 2 / m 3 ;k c ——Mass transfer rate, m / s; C f ——Mass concentration of acid in pores, mol / m 3 ; C s ——Acid concentration at the pore wall, mol / m 3 By changing the injection displacement q j The temperature field distribution is regulated by adjusting the injection time t, so that the temperature-responsive liquid gelling temporary plugging agent will not gel in the wellbore, but will gel in the formation as quickly as possible to achieve temporary plugging. The bottom hole pressure corresponding to the injection displacement should not be greater than the formation fracture pressure. S6: Repeat steps S3 to S5 to design the acidizing construction parameters for each section. When designing the last section, just repeat step 3.

2. The temporary plugging and acidification design method using a temperature-responsive temporary plugging agent according to claim 1, characterized in that: In step S2, if the reservoir is sandstone, the main acid liquid type should be a fluorine-containing acid system; if it is carbonate rock, the main acid liquid type should be a non-fluorine-containing acid system; if the main acid liquid type is a fluorine-containing acid system, a hydrochloric acid injection process should be added before and after the injection of the main acid; If the construction purpose requires deep penetration of the acid, the main acid system should be a slow acid system; if the construction purpose requires high dissolution, the main acid system should be an earth acid or hydrochloric acid system.

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