A method for calculating the amount of a liquid type deflecting agent

Abstract

The application discloses a kind of liquid type steering agent dosage calculation method, specific steps include: (1) obtaining basic data;(2) calculate the fracture morphology and size parameters of reservoir fracturing before temporary plugging;(3) with the target of productivity, optimize the best temporary plugging position in fracture;(4) temporary plugging diversion fracturing field test and numerical theoretical calculation two means determine the temporary plugging pressure required for diversion fracturing;(5) several liquid type steering agents that meet the conditions are preferred;(6) calculate the total filtration volume of liquid type steering agent during the process of moving from well bottom to the best temporary plugging position;(7) calculate the total miscible volume of steering agent during the process of moving from wellhead to the best temporary plugging position;(8) with the target of total price minimum and reservoir damage minimum, determine the final steering agent and dosage.The application combines theoretical calculation and field fracturing data, based on steering agent characteristics, temporary plugging position, fracture parameters, considers filtration and miscibility during injection, and scientifically calculates the amount of steering agent.

Description

TECHNICAL FIELD

[0001] The present application relates to the fracturing stimulation technology of oil and gas fields, in particular to a liquid diverting agent dosage calculation method, and belongs to the field of stimulation and reconstruction of oil and gas fields. BACKGROUND

[0002] For low-permeability and tight reservoirs with small brittleness index, large differential stress, high approach angle of natural fractures and hydraulic fractures, and underdeveloped natural fractures, conventional hydraulic fracturing or acid fracturing can only obtain simple fractures, the reconstruction volume is very small, and the single-well productivity is improved little, and the production decline rate is fast. Therefore, many scholars have proposed temporary plugging and diverting fracturing technology, and have carried out tests in oilfield sites, and have obtained certain effects, but the overall success rate needs to be improved, one of the main reasons is that the dosage of the diverting agent (also known as the temporary plugging agent) is not accurate, which causes the breakthrough pressure of the temporary plugging layer formed by the diverting agent to be lower than the temporary plugging pressure, and the temporary plugging layer is broken through. The solid diverting agent is limited by its own inherent size, it is difficult to pass through the sand control screen pipe, it needs to match the fracture size, the migration process from the wellhead to the deep part of the fracture is difficult to control, and it needs to be carried by fluid. Therefore, the liquid diverting agent has obvious advantages, it is not limited by the sand control completion tool and the fracture size, it does not need to be carried by fluid, it can be independently pumped, it changes from low-viscosity liquid to high-viscosity liquid or solid which is controlled by temperature, pH, time or ion concentration, and the pressure-bearing capacity of the temporary plugging layer is adjustable, but it also has the problem of inaccurate dosage. SUMMARY

[0003] The purpose of the present application is to solve the above problems, and a liquid diverting agent dosage calculation method is provided, and the specific technical scheme is as follows, and the idea is as shown in Figure 1 .

[0004] Step S1: Obtain reservoir and engineering parameters. The reservoir parameters include well trajectory, logging data, ground stress, stress difference coefficient, rock mechanics, natural fractures, bedding, brittleness, physical properties, etc. The engineering parameters include perforation data, injection fluid properties, injection volume and displacement, etc.

[0005] Step S2: Considering the influence of natural fractures, bedding, brittleness, stress difference coefficient, and multi-layer, etc., use FracMan or Kinetix fracturing software to calculate the fracture shape and size parameters of the reservoir before temporary plugging, and use the rectangular element with length a and width b to divide the fracture into M elements based on the boundary element method.

[0006] Step S3: Assume that the temporary plugging layer formed by the diverting agent will not be broken through, temporarily plug at different positions in the fracture in step S2, use FracMan fracturing software to calculate the fracture shape and size parameters of the reservoir after temporary plugging at different positions, import the obtained fracture parameters into CMG oil and gas reservoir simulation software, and simulate the obtained productivity under different temporary plugging positions, and the temporary plugging position corresponding to the highest productivity case is the best temporary plugging position L best .

[0007] Step S4: Collecting the data of the temporary plugging and diverting fracturing field test in the block, combining with the microseismic monitoring, downhole optical fiber monitoring, downhole television monitoring, etc., analyzing the pump injection curve of the fracturing construction, so as to determine the actual temporary plugging pressure P required by the temporary plugging and diverting fracturing in the block tem1 ; based on the elastic-plastic mechanics theory, the numerical calculation of the temporary plugging pressure P required by the temporary plugging and diverting fracturing tem2 ; the temporary plugging pressure P tem Take the larger value of the two, that is:

[0008] P tem = max(P tem1 , P tem2 ) (1)

[0009] In the formula: P tem , temporary plugging pressure, Pa; P tem1 , temporary plugging pressure obtained by field test, Pa; P tem2 , temporary plugging pressure obtained by theoretical calculation, Pa.

[0010] Step S5: Preliminary selection of multiple (W kinds) liquid diverting agents, indoor experiment to obtain the breakthrough pressure gradient P bre-k of various liquid diverting agents, calculation of the temporary plugging length L tem-k of various liquid diverting agents, determination of the maximum temporary plugging length L tem-max according to the best temporary plugging position obtained in step S3, and selection of the liquid diverting agent meeting the condition L tem-k <L tem-max The temporary plugging length L tem-k of different liquid diverting agents is:

[0011]

[0012] Step S6: Calculation of the total filtration volume of the liquid diverting agent during the migration from the well bottom to the best temporary plugging position. During the migration process, the properties of the liquid diverting agent are constantly changing, and the classical Cater filtration model cannot accurately calculate the filtration. The total injection time T of the liquid diverting agent is divided into N time steps, and the single time step is Δt; in the i th Δt, the liquid diverting agent has flowed to R i fracture units, and referring to the Darcy flow idea, the filtration volume of the liquid diverting agent in the i th Δt is:

[0013]

[0014] In the formula: K m-j , matrix permeability near the wall of the j th fracture unit, m 2 ; μ j , viscosity of the liquid diverting agent at the j th fracture unit, Pa·s; Pf-j Pj— the liquid diversion agent pressure at the jth fracture unit, Pa; P m-j lj— the matrix pore pressure near the jth fracture unit wall, Pa; l m-j — the fluid loss depth near the jth fracture unit, m.

[0015] Then, the total fluid loss volume of the liquid diversion agent from the well bottom to the optimal temporary plugging position is:

[0016]

[0017] The N-S equation represents the fluid flow in the fracture, the finite volume method is used to solve the fluid pressure in the fracture, the equivalent permeability tensor method is used to consider the natural fracture in the matrix, the Darcy equation represented by the full tensor of permeability is used to represent the fluid flow in the matrix, and the nineteen-point finite difference method is used to solve the matrix pore pressure near the fracture.

[0018] Step S7: Calculate the total miscible volume of the liquid diversion agent from the well head to the optimal temporary plugging position. Considering the viscous fingering phenomenon, the lattice-Boltzmann method is used to calculate the miscible zone length of the liquid diversion agent during the migration process with other fluids:

[0019]

[0020] Wherein:

[0021]

[0022] In the formula: C * — the dimensionless concentration of the liquid diversion agent; t * — the dimensionless time; u * — the dimensionless flow rate; Pe— Peclet number, representing the strength of the liquid diversion agent diffusion.

[0023] Then, the total miscible volume is:

[0024]

[0025] In the formula: L— fracture length, m; h— fracture height, m; w— fracture width, m.

[0026] Step S8: Calculate the amount V tem-k of the different liquid diversion agents selected in step S5 tem , with the goal of minimizing the total price of the liquid diversion agent and minimizing the damage to the reservoir, the final liquid diversion agent and its amount V tem are determined.

[0027]

[0028] The inventor found that the existing patents "CN106194145B A multi-stage temporary plugging deep network acid fracturing method", "CN113935093B A shale geology-engineering parameter-based internal diversion fracturing temporary plugging agent dosage design method", "CN110685657B A temporary plugging particle dosage calculation method for diversion fracturing", "CN111980652B A method for determining the type, size combination and dosage of in-slit temporary plugging agent", all describe temporary plugging agent (also known as diversion agent) dosage calculation methods, but they are for solid temporary plugging agents (such as particles, fibers, powders, etc.). Solid temporary plugging agents need to be pumped by fluid carrying, and the temporary plugging mechanism is filter cake or filter screen (large particle or long fiber bridge, small particle or short fiber filling), and the breakthrough pressure is mainly determined by the toughness of the filter cake or filter screen. CN106194145B and CN110685657B need to calculate the bridge particle dosage and filling particle dosage, respectively. CN111980652B and CN113935093B use API standard flow diversion chamber devices to simulate the temporary plugging process, the temporary plugging length is relatively short, the maximum is 15.85 cm, and the diversion agent dosage required for field fracturing is simply multiplied by the ratio of the reservoir fracture height and width to the experimental height and width. The laboratory test results are affected by factors such as rock plate size and carrying fluid type, and the simulated temporary plugging process is relatively simple, which has a large gap with the complex temporary plugging and diversion process in actual field construction. The existing patent "CN115898324A A method for optimizing temporary plugging diversion agent dosage" predicts the diversion agent dosage of future wells to be fractured by analyzing the apparent correlation between the reservoir characteristic data, design fracture characteristic data, diversion agent carrying fluid characteristic data, diversion agent characteristic data and the actual temporary plugging agent dosage of the well with good temporary plugging and diversion fracturing effect. The existing patent "CN109267985B A control method for temporary plugging diversion fracturing temporary plugging agent dosage" believes that the diversion agent will fill from the temporary plugging position to the fracture tip, and the diversion agent dosage is the entire fracture volume when plugging the fracture mouth, and the diversion agent dosage is the volume from the 1 / 3 of the fracture tip to the fracture tip when plugging at the 1 / 3 of the fracture tip. Obviously, the diversion agent dosage obtained by this calculation method is obviously too large, and it does not really calculate the actual required diversion agent dosage, which has a certain waste. The existing patent "CN113468831A A fracturing in-slit temporary plugging material dosage design method" calculates the support force P plug acting on the plugging layer in step S3 plug =(P fmouse w plug_mouse -P ftip w plug_tip ) / [2a(1-φ)tanδ3], and step S5 judges whether the fracture plugging layer friction instability strength criterion is met, if not, steps S3-S5 are repeated, but the fracture plugging layer friction instability strength criterion in step S5 is hP fmouse w plug_mouse-hP ftip w plug_tip ≤hP plug 2a(1-φ)tanδ3, this formula is arranged after dividing h on both ends, P plug ≥(P fmouse w plug_mouse -P ftip w plug_tip ) / [2a(1-φ)tanδ3], obviously, the condition of step S5 will be automatically met after step S3 is performed, in addition, it does not consider the diversion agent and other fluid miscible caused by the diversion agent filtration and viscosity during the injection process. The existing patents "CN114592823A determination method of temporary plugging diversion material dosage and application" and "CN114592840A temporary plugging and fracturing method and its application", the two patents have the same invention content, both think that the diversion agent dosage is proportional to the square of the fracture length and width, the diversion agent density and the permeability of the temporary plugging layer formed, and inversely proportional to the viscosity and displacement of the carrying fluid, the theoretical basis is insufficient, the permeability of the temporary plugging layer formed by the liquid diversion agent is almost 0, so the dosage cannot be calculated, therefore, it is only suitable for solid diversion agent.

[0029] Compared with the prior art, the main differences of the present application are: (1) different application objects, different temporary plugging mechanisms, and different dosage design ideas: the existing patents are mainly for solid diversion agents, which need to be carried by fluid pumps, the temporary plugging mechanism is filter cake or filter screen (large particles or long fiber bridge, small particles or short fiber filling), and the breakthrough pressure is mainly determined by the toughness of the filter cake or filter screen, and the dosage of the large particles or long fibers of the bridge and the small particles or short fibers of the filling need to be calculated respectively; the present application is for liquid diversion agent, which can be independently pumped, the temporary plugging mechanism is volume plugging, the breakthrough pressure is mainly determined by the temporary plugging length, and only one kind of liquid diversion agent dosage needs to be calculated; (2) different dosage calculation methods: most of the existing patents obtain the diversion agent dosage through indoor experiments, and then enlarge the required dosage in the field through simple similarity principle, the temporary plugging length of indoor experiment is short, and the experimental results are affected by many experimental factors, or the apparent correlation between reservoir, fracture, diversion agent characteristics and diversion agent dosage is obtained through simple multiple regression analysis of field fracturing test data, so as to predict the required diversion agent dosage for fracturing of other wells, without analyzing the actual required diversion agent dosage from the mechanism; the present application combines numerical theoretical calculation and field fracturing test data to determine the temporary plugging pressure, and then combines the characteristics of liquid diversion agent, temporary plugging position and fracture parameters, considers the filtration and miscibility of liquid diversion agent during the injection process, and scientifically calculates the diversion agent dosage, the calculated diversion agent dosage is accurate and reasonable, without waste.

[0030] The present application has the advantages that: the present application is directed to liquid diverting agent, through theoretical calculation and field fracturing data combination, based on liquid diverting agent characteristics, temporary plugging position, fracture parameters, considering filtration and miscible phase in injection process, scientific calculation of diverting agent dosage, the result is reasonable, no waste. BRIEF DESCRIPTION OF DRAWINGS

[0031] Figure 1 The flow chart for liquid diverting agent dosage calculation.

[0032] Figure 2 The wellbore trajectory of S well.

[0033] Figure 3 The ground stress distribution of S well.

[0034] Figure 4 The fracture grid division of S well before temporary plugging.

[0035] Figure 5 The capacity increase ratio corresponding to temporary plugging at different positions in S well fracture. DETAILED DESCRIPTION

[0036] The preferred embodiments of the present application are described below in conjunction with the accompanying drawings, and it should be understood that the preferred embodiments described herein are only used to illustrate and explain the present application, and are not used to limit the present application.

[0037] Step S1: taking WSQ block as an example, the wellbore trajectory of S well is as shown in Figure 2 , the ground stress distribution calculated according to logging data is as shown in Figure 3 , the horizontal stress difference coefficient is 0.11-0.216, the Young's modulus is 16.2 GPa, the Poisson's ratio is 0.22, the natural fracture line density is 0.2 / m, the angle with the maximum horizontal stress direction is about 75°, the natural fracture cohesion is 10 MPa, the natural fracture friction coefficient is 0.6, the rock tensile strength is 3 MPa, there is no bedding, the brittleness index is 40.4%, the porosity is 8.9%, the permeability is 5.23x10 -3 μm 2 , the perforation density is 16 holes / m, the 10 mm hole diameter, the 60° phase angle, the spiral hole arrangement, the injection fluid viscosity is 26 mPa·s, the density is 1050 kg / m 3 , the displacement is 6 m 3 / min, the injection fluid volume before temporary plugging is 100 m 3 , and the injection fluid volume after temporary plugging is 80 m 3 .

[0038] Step S2: The FracMan software is used to calculate the fracture shape and size parameters of the reservoir before temporary plugging. Since the approaching angle between the natural fracture and the hydraulic fracture is as high as 75°, the hydraulic fracture directly penetrates the natural fracture. The fracture is divided into 195 units using a rectangular unit with a length a = 6 m and a width b = 3 m, as shown in FIG. 2. Figure 4 .

[0039] Step S3: The FracMan software is used to calculate the reservoir fracture parameters after temporary plugging at the positions of 5 m, 15 m, 35 m, 55 m, and 75 m in the length direction of the fracture. The obtained fracture parameters are introduced into the CMG oil and gas reservoir simulation software to simulate the obtained productivity under different temporary plugging positions, as shown in FIG. 3. The optimal temporary plugging position L Figure 5 is 55 m in the fracture. best

[0040] Step S4: Based on the field test results of the temporary plugging and diverting fracturing wells in the same layer around the S well, the actual temporary plugging pressure P tem1 required by the temporary plugging and diverting fracturing of the S well is determined to be 15.8 MPa. Based on the elastic-plastic mechanics theory, the numerical calculation of the temporary plugging pressure P tem2 required by the temporary plugging and diverting fracturing is 17.2 MPa. The temporary plugging pressure P tem is taken as the larger value of the two, i.e., 17.2 MPa.

[0041] Step S5: Five kinds of liquid diverting agents (DA-1, DA-2, DA-3, DA-4, and DA-5) are initially selected. The breakthrough pressure gradients P bre-k of various liquid diverting agents obtained through indoor experiments are 0.51, 0.87, 0.62, 1.53, and 1.32 MPa / m, respectively. The temporary plugging lengths L tem-k of various liquid diverting agents are 33.73, 19.77, 27.74, 11.24, and 13.03 m, respectively. According to the optimal temporary plugging position obtained in step S3, the maximum temporary plugging length L tem-max is 27 m. The liquid diverting agents that meet the condition of L tem-k <L tem-max are DA-2, DA-4, and DA-5 liquid diverting agents.

[0042] Step S6: The total filtration loss volumes of DA-2, DA-4, and DA-5 liquid diverting agents during the process of moving from the well bottom to the optimal temporary plugging position are 12.1, 8.3, and 9.7 m 3 , respectively.

[0043] Step S7: The total miscible volumes of DA-2, DA-4, and DA-5 liquid diverting agents during the process of moving from the well bottom to the optimal temporary plugging position are 3.8, 2.4, and 2.9 m 3 , respectively.

[0044] ​Step S8: the dosage V of DA-2, DA-4, DA-5 liquid diverting agent tem-k 20.6, 13.4 and 15.7 m 3 With the lowest total price of liquid diverting agent and the smallest reservoir damage as the goal, the final diverting agent is preferably determined as DA-4 liquid diverting agent, with a dosage of 13.4 m 3 .

[0045] The above is only the preferred embodiment of the present application, and does not limit the present application in any form. Although the present application has been disclosed as above with the preferred embodiment, it is not intended to limit the present application. Any person skilled in the art can make some changes or modifications to the above disclosed technical content without departing from the technical solution of the present application, and any simple modification, equivalent change and modification of the above embodiment according to the technical essence of the present application still belong to the scope of the technical solution of the present application.

Claims

1. A method of calculating the amount of a liquid type of a steering agent, characterized by, The method comprises the following steps: S1: obtaining reservoir and engineering parameters; reservoir parameters include wellbore trajectory, logging data, ground stress, stress difference coefficient, rock mechanics, natural fracture, bedding, brittleness and physical property; engineering parameters include perforation data, injected fluid property, injected fluid volume and displacement; S2: considering the influence of natural fracture, bedding, brittleness, stress difference coefficient and multi-layer factors, using FracMan or Kinetix fracturing software to calculate the fracture shape and size parameters of the reservoir before temporary plugging, and using a long a and wide b rectangular element to divide the fracture into M elements based on the boundary element method; S3: Assuming that the temporary plugging layer formed by the diverting agent will not be broken through, temporary plugging is performed at different positions in the fracture in step S2, and the FracMan fracturing software is used to calculate the reservoir fracture shape and size parameters after temporary plugging at different positions. The obtained fracture parameters are introduced into the CMG oil and gas reservoir simulation software, and the obtained productivity under different temporary plugging positions is simulated. The temporary plugging position corresponding to the highest productivity case is the best temporary plugging position L best ; S4: Collecting the data of temporary plugging and diverting fracturing field test in the block, combining with microseismic monitoring, downhole optical fiber monitoring or downhole television monitoring, analyzing the pump injection curve of fracturing construction, so as to determine the actual temporary plugging pressure P required by temporary plugging and diverting fracturing in the block tem1 ; Based on the theory of elastic-plastic mechanics, the numerical calculation of the temporary plugging pressure P required by temporary plugging and diverting fracturing tem2 ; The temporary plugging pressure P tem Take the larger value of the two; S5: Initially select W types of liquid diverting agents, and obtain the breakthrough pressure gradient P of each liquid diverting agent in indoor experiments. bre-k Calculate the temporary plugging length L of various liquid diverting agents. tem-k The maximum value of the temporary blocking length L is determined based on the optimal temporary blocking position obtained in step S3. tem-max Choose the option that satisfies L tem-k <L tem-max Conditions for liquid diverting agents; temporary plugging length L for different liquid diverting agents tem-k for: S6: calculating the total filtration volume of the liquid diverting agent in the process of moving from the well bottom to the optimal temporary plugging position; Dividing the total injection time T of the liquid diverting agent into N time steps, and the single time step is Δt; At the ith Δt, the liquid diversion agent has flowed to R i At the ith Δt, the liquid diversion agent has flowed to R At the ith Δt, the liquid diversion agent has flowed to R At the ith Δt, the liquid diversion agent has flowed to R At the ith Δt, the liquid diversion agent has flowed to R At the ith Δt, the liquid diversion agent has flowed to R At the ith Δt, the where: K m-j — matrix permeability near the jth fracture unit wall, m 2 ; μ j — liquid diversion agent viscosity at the jth fracture unit, Pa-s; P f-j — liquid diversion agent pressure at the jth fracture unit, Pa; P m-j — matrix pore pressure near the jth fracture unit wall, Pa; l m-j — fluid loss depth near the jth fracture unit, m; The total filtration volume of the liquid diverting agent in the process of moving from the well bottom to the optimal temporary plugging position is: N-S equation represents the fluid flow in the fracture, and the finite volume method is used to solve the fluid pressure in the fracture; the equivalent permeability tensor method is used to consider the natural fracture in the matrix, the Darcy equation represented by the full tensor of permeability is used to represent the fluid flow in the matrix, and the nineteen-point finite difference method is used to solve the pore pressure of the matrix near the fracture; S7: calculating the total miscible volume of the liquid diverting agent in the process of moving from the well top to the optimal temporary plugging position; Considering the viscous fingering phenomenon, using the lattice-Boltzmann method to calculate the miscible length of the liquid diverting agent with other fluids in the process of moving: Wherein: where: C * — dimensionless concentration of liquid diverting agent; t * — dimensionless time; u * — dimensionless flow rate; Pe — Peclet number, which characterizes the strength of diffusion of the liquid diverting agent; Then, the total miscible volume is: In the formula: L is the length of the fracture, m; h is the height of the fracture, m; w is the width of the fracture, m; S8: calculating the amount V of the selected different liquid diverting agent in step S5 tem-k The final liquid diverting agent and its amount V are preferably determined with the lowest total price of the liquid diverting agent and the least reservoir damage as the target tem-k ; The amount V of the liquid type turning agent tem-k is: In the formula: V tem-k - the amount m of liquid turning agent 3 .

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