CN116950630A - Method for designing fracturing flowback system after staged fracturing of tight gas reservoir horizontal well - Google Patents
Method for designing fracturing flowback system after staged fracturing of tight gas reservoir horizontal well Download PDFInfo
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Abstract
The invention provides a tight gas reservoir horizontal well a method for designing a fracturing flowback system after staged fracturing, belongs to the technical field of flowback after fracturing of oil and gas fields. Acquiring a pressure initial value at a wellhead of a back flow stage after pressure, and calculating the pressure at the tail end of a shaft through a shaft pressure drop and pipe flow friction pressure drop model; the wellbore end pressure is calculated as the fracture average pressure, the average pressure of the fracture is calculated and, the average pressure of the cracks minus the pressure loss during flowback, obtaining new wellhead pressure; acquiring the static critical flow rate of the propping agent in the crack, and calculating the wellhead drainage flow rate under the corresponding critical flow rate; according to the pre-acquired corresponding relation between the wellhead pressure and the drain flow rate and the diameter of the oil nozzle, determining the diameter of a choke to be adopted under the current critical drainage flow rate corresponding to the new wellhead pressure, and in the back flow process after the pressure, repeating the process, and continuously adjusting the oil nozzle until the average pressure of the cracks reaches the closing pressure. By adopting the method, the crack closing speed can be improved, and the propping agent backflow can be reduced.
Description
Technical Field
The invention provides a tight gas reservoir horizontal well a method for designing a fracturing flowback system after staged fracturing, belongs to the field after fracturing the technical field of flowback.
Background
The staged fracturing of the current tight oil and gas reservoir horizontal well is developed for many years, and a fracturing process technology taking the staged fracturing of a soluble bridge plug and the bottom sealing dragging fracturing process of a continuous oil pipe as a main mode and the staged fracturing of a multistage external packer and the staged fracturing of a hydraulic jet dragging tubular column as an auxiliary mode is formed in the Erdos work area.
In recent years, the north-jaw gas field is mainly developed by a horizontal well, the length of the horizontal section is in the range of 800-1000 meters, the main reservoir is a stone river subgroup, a Shanxi subgroup and a Taiyuan subgroup, the fracturing process mainly comprises staged fracturing of a soluble bridge plug, dragging of a continuous oil pipe with a bottom seal and fracturing of a naked eye preset tubular column, and the fracturing fluid is a conventional guanidine gum fracturing fluid system. Through continuous exploration and improvement of the fracturing process, the staged sand fracturing modification process of the horizontal well is mature, but the matched post-fracturing flowback process still has certain defects:
(1) Determining a back flow system after pressure by experience, wherein the gas period difference is large, and the construction progress is influenced;
(2) The flowback rate of part of the wells is low, and the transformation effect is affected;
(3) The sand production condition is serious in the process of partial well flowback.
The flow back condition is not ideal, so that the fracturing fluid cannot be quickly and timely discharged back to the reservoir, the reservoir is damaged, and the effect of the yield increasing measure is greatly influenced. In the past determination of the size of the discharge nozzle, most of the experience was adopted, and different people may give different nozzle sizes. The bigger oil nozzle can cause the diversion capacity at the seam to be greatly reduced due to the backflow of the propping agent; the smaller the nozzle tip, the higher the proportion of the proppant settling bottom may be, which also affects the final fracturing effect.
In conclusion, after staged fracturing of a tight oil and gas reservoir horizontal well, a choke flowback fracturing fluid with a proper size cannot be selected, the flowback rate after fracturing is low, and the oil and gas yield is low.
Disclosure of Invention
The invention aims to provide a method for designing a fracturing flowback system after staged fracturing of a tight gas reservoir horizontal well, which is used for solving the problems of low flowback rate and low oil and gas yield after staged fracturing of the tight gas reservoir horizontal well.
In order to achieve the purpose, the invention provides a method for designing a fracturing flowback system after staged fracturing of a tight gas reservoir horizontal well, which comprises the following steps:
1) Acquiring an initial value of wellhead pressure, and calculating the pressure at the tail end of a shaft through a shaft pressure drop and pipe flow friction pressure drop model;
2) Taking the pressure at the tail end of the shaft as an initial value of the average pressure of the crack, calculating the average pressure of the crack, subtracting the pressure loss in the flowback process from the average pressure of the crack, and calculating the new wellhead pressure;
3) Obtaining a critical flowback flow rate of a propping agent stationary in a crack in a flowback process, and performing forward pushing calculation from a bottom of a well to a wellhead to obtain a fracturing fluid flowback critical flow rate at the wellhead;
4) Determining the diameter of the choke plug to be adopted under the condition of corresponding new wellhead pressure and the current wellhead flowback critical flow rate according to the pre-acquired corresponding relation between wellhead pressure and the wellhead flowback critical flow rate of the fracturing fluid and the diameter of the choke plug;
5) And (3) taking the new wellhead pressure in the step (2) as an initial value of the wellhead pressure, and repeating the steps (1) to 4) until the average fracture pressure reaches the closing pressure.
Acquiring a pressure initial value at a wellhead of a back flow stage after pressure, and calculating the pressure at the tail end of a shaft through a shaft pressure drop and pipe flow friction pressure drop model; taking the pressure at the tail end of the shaft as an initial value of calculation of the average pressure of the crack, calculating the average pressure of the crack, and subtracting the pressure loss in the flowback process from the average pressure of the crack to obtain new wellhead pressure; acquiring the static critical flow rate of the propping agent in the crack, and calculating the wellhead drainage flow rate under the corresponding critical flow rate; according to the corresponding relation between the pre-acquired wellhead pressure and the drain flow rate and the diameter of the oil nozzle, determining the diameter of the oil nozzle which is needed to be adopted under the current critical drain flow rate and corresponding to the new wellhead pressure, and repeating the processes in the back flow process until the average pressure of the cracks reaches the closing pressure. By adopting the method, the crack closing speed can be improved, and the propping agent backflow can be reduced.
Further, in the above method, in step 5), the correspondence between the wellhead pressure and the drain flow rate and the diameter of the choke is determined by the following method:
and (3) calibrating the flow rate of liquid discharge at the oil nozzle as the flow rate of liquid discharge corresponding to the wellhead pressure and the diameter of the oil nozzle when the oil nozzles with different diameters are adopted for flowback under wellhead pressures with different sizes through experiments.
By the method of experimental calibration, different wellhead pressures are simulated by adopting oil nozzles with different diameters, and flowback experiments are carried out, so that the flowing speed of the liquid discharge corresponding to the different wellhead pressures and the different oil nozzle diameters is obtained. The wellhead pressure and the diameter of the oil nozzle can be adjusted according to actual conditions by adopting an experimental calibration method, so that the observation and the operation are convenient.
Further, in the above method, in step 5), the critical flowback flow rate of the proppant while stationary in the fracture is calculated from a fracture flowback initiation model of the proppant in the fracture.
The method is characterized in that the actual condition of the propping agent in the crack is analyzed through a fracturing flowback starting model of the propping agent in the crack, and the calculated critical flowback flow is more accurate.
Further, in the method, in the step 1), the pump stopping pressure when the fracturing fluid stops being injected is taken as the wellhead pressure initial value.
The initial value of the wellhead pressure adopts the pump stopping pressure when the fracturing fluid stops injecting, so that the acquisition is convenient.
Further, in the method, fiber proppants are adopted for sand fracturing in the fracturing stage before the flowback process.
The propping agent added with the fiber has strong stability, and is beneficial to preventing the propping agent from flowing back, thereby improving the flow back rate.
Further, in the method, liquid nitrogen is adopted for accompanying injection in a fracturing stage before the flowback process, wherein the fracturing stage comprises a pre-fracturing stage and a post-fracturing stage, and the injection amount of liquid nitrogen in the pre-fracturing stage is larger than that in the post-fracturing stage.
The liquid nitrogen injection amount is increased in the first stages of fracturing construction of the horizontal well fracturing, the liquid nitrogen injection amount can be reduced step by step in the subsequent stages of fracturing construction, the efficiency of discharging fracturing fluid in the liquid discharge process can be improved, the frequency of replacing a choke is reduced, and the flowback efficiency after fracturing is improved.
Drawings
FIG. 1 is a flow chart of a method for designing a fracturing flowback system after staged fracturing of a tight gas reservoir horizontal well in an embodiment of the invention;
FIG. 2 is a schematic diagram of a horizontal well fracturing flowback in an embodiment of the present invention;
FIG. 3 is a schematic diagram of a predicted drop curve of wellhead oil pressure in an embodiment of the present invention;
FIG. 4 is a schematic diagram of a flowback curve after fracturing of a high-yield well according to an embodiment of the present invention;
FIG. 5 is a schematic diagram of a flowback profile after fracturing of a production well in an embodiment of the present invention;
FIG. 6 is a schematic diagram of a flowback profile after fracturing of a low-producing well in an embodiment of the present invention;
FIG. 7 is a schematic illustration of a mechanism of proppant flowback in a fracture in an embodiment of the invention;
FIG. 8 is a schematic view of a horizontal well bore structure in accordance with an embodiment of the present invention;
FIG. 9 is a schematic diagram of a main interface of the back flow software after horizontal well pressure in an embodiment of the present invention;
FIG. 10 is a schematic diagram of an input/output interface of the back flow software after horizontal well pressure in an embodiment of the present invention;
FIG. 11 is a schematic diagram of the relationship between different wellhead pressures and optimal return nozzle diameters in an embodiment of the present invention;
FIG. 12 is a schematic diagram of wellhead pressure drop curves when a DPH-3 well selects different nozzles for flowback in an embodiment of the invention;
FIG. 13 is a schematic diagram showing the relationship between the wellhead pressure and the critical flow rate in the fracture when a DPH-3 well selects a 2mm choke for flowback in an embodiment of the present invention;
FIG. 14 is a schematic diagram showing the relationship between wellhead pressure and critical flow rate in a fracture when a 4mm nozzle is selected for flowback in a DPH-3 well in an embodiment of the present invention;
FIG. 15 is a schematic diagram showing the relationship between wellhead pressure and critical flow rate in a fracture when a DPH-3 well selects a 6mm choke for flowback in an embodiment of the present invention;
FIG. 16 is a graph showing the bottom hole pressure as a function of flowback time for DPH-3 wells using different diameter nozzles in accordance with an embodiment of the present invention;
FIG. 17 is a schematic diagram showing the wellhead pressure change of a DPH-3 well according to the flowback time after selecting different nozzles in an embodiment of the present invention;
FIG. 18 is a graph of proppant force analysis in an embodiment of the present invention.
Detailed Description
The present invention will be described in further detail with reference to the drawings and examples, in order to make the objects, technical solutions and advantages of the present invention more apparent.
Method example 1:
for hydraulic fracturing of a low-permeability tight reservoir horizontal well, if the horizontal well is naturally closed only by a crack after the horizontal well is pressed, the horizontal well is often long in time, so that a crack forced closing technology is generally adopted in hydraulic fracturing design and construction. According to the method for designing the fracturing flowback system after staged fracturing of the tight gas reservoir horizontal well, provided by the invention, on the basis of considering two-dimensional filtration of fracturing fluid and flowing in a fracturing fluid shaft, a material balance principle, fluid mechanics and related theory of rock fluid mechanics are utilized to build a crack forced closure mathematical model, and the change rule between oil nozzles with different diameters and corresponding wellhead pressures in the crack forced closure process is analyzed, so that a theoretical basis is provided for on-site constructors to select proper flowback time and oil nozzles during forced flowback.
As shown in FIG. 1, the method for designing the fracturing flowback system after staged fracturing of the tight gas reservoir horizontal well comprises the following steps:
step S1: and establishing a crack forced closure model. The forced closure model of the fracture comprises a pressure iteration solving formula, a speed inverse solving formula and a propping agent backflow solving formula.
In establishing the forced closure model of the crack, the following assumption conditions need to be set:
(1) the height of the front edge of the crack is constant and is equal to the effective thickness of the fracturing layer;
(2) the viscosity of the fracturing fluid changes linearly from the bottom of the well to the seam end or the viscosity of the fracturing fluid is constant;
(3) the crack is free to close without being influenced by the propping agent, and the crack is only closed by reducing the crack width, and the crack height and the crack length are unchanged;
(4) after stopping the pump, the crack immediately stops extending;
(5) the break time of the liquid after addition of the break liquid, i.e. the instantaneous break, is ignored.
On the basis of the assumption condition of the forced closure model of the crack, comprehensively analyzing and researching the mechanism of the crack flowback after the horizontal well is fractured, and on the basis, establishing a corresponding mathematical model aiming at the well body structure of the horizontal well in FIG. 2, and optimizing the flowback effect.
The mathematical model is as follows:
a sand-carrying fluid flow model formula in a shaft:
according to the volume balance principle, when the fracturing fluid is forced to flow back, the variation of the volume of the fracture is equal to the sum of the total filtrate loss and the flow back capacity of the fracturing fluid at the moment of flow back.
ΔV f ＝V Row of rows +V loss
In the process of flowback of the fracturing fluid, because oil pipe resistance and gravity need to be overcome, when the fracturing fluid reaches a wellhead, the pressure is reduced, and the relation is as follows:
P t ＝P f -P h -ΔP
wherein: p (P) f -pressure of the tubing at the fracture MPa;
the delta P is Cheng Mazu MPa along the pipeline in the process of fracturing fluid flowback;
P h -hydrostatic column pressure for well bore, MPa
The fracturing also has its back-flow capacity and total fluid loss calculated separately below. If the uniform speed flowback is performed, the accumulated flowback volume is expressed as follows:
V row of rows ＝Δt×v×S Oil nozzle ＝Δt×v×π×r 2
The speed of the flowback is changed, and the corresponding flowback flow Q and accumulated flowback volume V in unit time are obtained Row of rows The calculation formula is as follows:
in the formula, since the wellhead pressure P (t) in the integral formula is a nonlinear function, in order to solve the function, a compound trapezoidal integral formula is adopted to solve the function.
Wherein,,
in the above formula, deltat is the time step and is consistent with the following method for obtaining the filtration loss; superscript n denotes t n Time; p (t) o ) Representing the pressure at the wellhead just after flowback, if flowback is performed immediately after pump down, then P (t o ) Is equal to the instantaneous pump stopping pressure P after fracturing Stop and stop 。
V Row of rows In the process of flowback, the bottom pressure P is followed f And, at t n Time t 1 To t n-1 The fracture pressure value at the moment has been found,only +.>Is a function of:
in the process of fracturing fluid flowback, when wellhead pressure is calculated, many students neglect the friction pressure drop of a pipeline of a shaft for the convenience of calculation. Here, the model considers the friction pressure drop of the shaft, so that the calculation result is more accurate and reliable.
The friction pressure drop calculation formula of the fracturing fluid comprises the following steps:
(1) newtonian fluid flow friction pressure drop calculation:
newtonian fluid friction is related to the fluid flow regime, the flow regime of the fluid being determined by the Reynolds number:
when N is Re And less than or equal to 2100, the fluid flow is laminar, and the friction coefficient is:
when N is Re Fluid flow is turbulent and friction coefficient is:
along-path hydraulic friction coefficient:
pressure drop along Cheng Shuili:
wherein: n (N) Re A Reynolds number, dimensionless;
mu-viscosity of gel breaking fracturing fluid, mPa.s;
v-fluid flow rate in the column, m/s;
d is the diameter of the tubular column, m;
ρ -fracturing fluid density, kg/m 3 。
Calculating friction pressure drop of the fracturing fluid:
(2) and (3) calculating friction pressure drop of the power law type fracturing fluid:
the fracturing fluid mostly shows the property of power law type liquid, and can be used for approximating the apparent viscosity mu of the flowing of the fracturing fluid in a tubular column a Instead of μ in newtonian liquid formula, i.e.:
the power law fluid reynolds number is:
wherein: consistency coefficient of Ka-fracturing fluid flowing in well bore, kg.s n /m 2 ；
n-rheological index of fracturing fluid.
Regarding Reynolds number calculation and flow state discrimination of non-Newtonian flow, a calculation method of Newtonian flow is currently adopted. When N' Re At less than or equal to 2100, the fluid flow is laminar; when N' Re At > 2100, flowThe bulk flow is turbulent. The friction coefficient of different flow states can be calculated by approximately using the friction pressure drop formula of Newtonian fluid round tube, and only N in the formula is needed Re Change to N' Re And (3) obtaining the product.
Establishing a horizontal well crack and horizontal well shaft coupling formula:
during the flow of the fracturing fluid to the wellbore, the fracture forms a communication system with the tubing. Therefore, it is necessary to establish a horizontal well fracture and horizontal well wellbore coupling formula, and when the flowback speed of the fracturing fluid in the oil pipe is known, the approximate flowback speed of the fracturing fluid in the fracture can be obtained according to the system.
From continuity equation 2v 2 L h L w ＝v 1 πR 2 Obtaining the flow rate of the fracturing fluid in the fracture:
sand carrying fracturing fluid produces sand patterns in horizontal well cracks:
proppant flowback model schematic: if none of the last section of proppant injected during flowback is carried out of the fracture by the fracturing fluid of the flowback, then the proppant injected previously will not be carried out either.
In the process of fracturing fluid flowback, propping agent is suspended in fracturing fluid under the impact of the fracturing fluid, and some propping agent flows to the bottom of the well, so that the critical flowback speed of the fracturing fluid for transporting the propping agent is necessarily existed, according to the assumed condition, as shown in fig. 18, the propping agent rolls by taking the point A as a fulcrum under the action of the impact force of fluid and the effective gravity, and the dragging resistance is as follows:
in the design calculation of hydraulic fracturing, C d The calculation is generally performed by using a Norwtini formula, namely:wherein,,
according to the moment balance principle, the method comprises the following steps:
F x L 1 +F y L 2 ＝W o L 3
for simplicity, assume that the lifting force is equal to the drag force, i.e.:
when N is Re At less than or equal to 2, k=24, τ=1,
when 2 is less than N Re At less than or equal to 500, k=18.5, τ=0.6,
when N is Re >500, k=0.44, τ=0,
wherein: d, d s -diameter of individual proppants, m; ρ s Density of proppants, kg/m 3 The method comprises the steps of carrying out a first treatment on the surface of the A-windward area of proppant, m 2 ；C d -coefficient of resistance.
Step S2: in the proppant flowback solution formula, the forced closure pressure of the fracture and the critical flow rate of the proppant in the fracture are calculated through a starting model of the proppant in the fracture.
In the pressure iteration solving formula, the pump stopping pressure is used as a wellhead pressure starting point, a pressure value at the tail end of a shaft is obtained through calculation through a shaft pressure drop and pipe flow friction pressure drop model, the pressure value at the tail end of the shaft is used as an initial value for calculating the average pressure of a crack, and a substance balance equation is utilized: fracture volume change = fracturing fluid loss + wellhead flowback volume, fracture mean pressure is calculated.
And in the whole flowback process, subtracting the pressure loss in the flowback process by using the obtained average pressure of the cracks to obtain the new wellhead pressure.
In a speed reverse calculation solution formula, different wellhead pressures are known, the flow velocity V1 of the liquid discharge of the oil nozzle at the wellhead is calculated according to a coupling model of the oil nozzle and a shaft, reverse calculation is carried out on the flow velocity of the liquid discharge of the oil nozzle from the wellhead to the bottom of the well through a continuity equation, and the flow velocity V2 of the liquid discharge of the fracturing fluid in the crack in the horizontal well fracturing flow-back process is calculated. In order to ensure that the fracture does not sand out, the flow-back speed V2 of the fracturing fluid in the fracture is less than or equal to the critical flow speed V3 of the propping agent in the fracture.
The coupling model of the oil nozzle and the shaft is as follows:
for the wellhead and the drop nozzle, the equation is given by bernoulli:
the liquid discharge amount at the outlet of the oil pipe is equal to the return discharge amount of the oil nozzle, and is obtained by a continuity equation:
obtaining flowback flow rates at different moments according to a formula (2-6-1) and a formula (2-6-2):
wherein: p (P) t -wellhead oil pressure, MP;
P o -the pressure at the outlet of the nozzle, taking the standard atmospheric pressure, 0.1MP;
v-flowback fracturing fluid wellhead flow rate, namely the nozzle tip spraying speed, m/s;
v 1 -flowback fracturing fluid wellbore flow rate, m/s;
ζ -local drag coefficient, dimensionless, here taken as 0.5;
r-radius of the oil nozzle, m; r is the radius of the shaft, m;
ρ -fracturing fluid density, kg/m 3 ；
Gamma-severity of fracturing fluid, ρg.
The flow rate of the oil nozzle increases with the pressure of the wellhead, the flow rate of the oil nozzle increases with the diameter of the oil nozzle under the condition of the oil pressure of the wellhead, and the discharge amount of the oil nozzle decreases with the diameter of the oil nozzle. Therefore, in order to select a choke with a proper size, sand is prevented from being produced in a crack in the fracturing flowback process of the horizontal well, the flowback flow speed V2 is enabled to be equal to the critical flow speed V3, and then forward pushing calculation from the bottom of the well to the wellhead is carried out on a speed reverse pushing solution formula, so that the critical drainage flow speed V1 of the fracturing fluid at the wellhead is obtained.
And (3) taking the new wellhead pressure as a wellhead pressure starting point, repeating the steps, and repeatedly iterating again to calculate the new average fracture pressure after liquid drainage until the average fracture pressure reaches the closing pressure.
Because the drainage flow rate at the wellhead is controlled by the wellhead pressure and the diameter of the oil nozzle, a reasonable flowback oil nozzle is selected according to the corresponding relation between the wellhead pressure and the drainage flow rate calibrated in advance and the diameter of the oil nozzle according to the new wellhead pressure and the drainage flow rate V1 obtained by iteration, so that the crack is prevented from producing sand, and the aim of increasing the oil and gas production is fulfilled. Thus, through the wellhead oil pressure drop prediction curve shown in fig. 3, the time for replacing the oil nozzle can be controlled, and the fracturing fluid can be quickly discharged back from the crack on the premise of ensuring no sand production as much as possible.
Method example 2:
the fracturing gas test data of staged fracturing wells of the horizontal wells of the fields of Niu Deqi fields and eastern-win fields in recent years are collected and arranged, the wells with the non-resistance flow rate of more than 10 multiplied by 104m < 3 >/d are determined to be high-yield wells, 4 to 10 multiplied by 104m < 3 >/d are medium-yield wells, and less than 4 multiplied by 104m < 3 >/d are low-yield wells according to the size of the non-resistance flow rate of the tested gas, and the liquid discharge characteristics after the pressure of the horizontal wells with different productivity are summarized and analyzed respectively, so that the basis is provided for optimizing the liquid discharge system after the pressure.
According to the fumbling of the following-pressure flowback system of the horizontal well of the Huidos gas field in recent years, the working system (the specific size is selected in combination with the wellhead pressure condition) of controlling the oil discharge nozzle by taking a 3mm-5mm oil nozzle as a crack forced closing stage is formed on site preliminarily, and the requirements of controlling the crack closing and preventing the propping agent from flowing back by liquid discharge after pressure are basically met.
By adopting the design method of the fracturing flow-back system after staged fracturing of the tight gas reservoir horizontal well, in the field operation process of high, medium and low yield wells, the control and selection of the oil nozzle are specifically implemented as follows:
the stratum physical property of the high-yield well is good, the fracturing fluid pressed into the stratum is easy to diffuse to the stratum at a distance, the pressure of fracturing injection is basically released in the stage of amplifying discharge and blowout, then the oil pressure is quickly rebounded and gradually increased to a higher level, the rising speed is higher, the gas yield is gradually increased along with the rising of the pressure of a wellhead, and the daily drainage volume is generally reduced to 30m 3 The following is given.
As shown in FIG. 4, the high-yield well can undergo three stages of closed control, discharge amplification and pressure rise in the liquid discharge stage of the open-end injection, and the continuous liquid discharge can be controlled by a nozzle tip to achieve the production condition.
The working system in the closed control stage is as follows: the 3-5 mm oil nozzle is selected at the stage, usually 1-2 hours are needed to forcedly close the cracks in the stratum, when the bottom hole pressure is lower than the forcedly closing pressure of the cracks, the stratum is closed, then the oil nozzle is properly enlarged, and the closing control stage is finished.
The working system in the amplified displacement stage is as follows: usually, a 5-15mm oil nozzle is selected for control or free discharge, the stratum is not produced with sand (sand particles are not produced at the outlet of a discharge pipe line) as a control principle, the elastic liquid discharge of the fractured stratum is fully utilized, and the liquid discharge amount is maximum. The amplified displacement stage has the following characteristics:
(1) the initial effluent is mainly liquid, is plug flow, and is gas-liquid two-phase flow in the later stage, and the gas and water are sprayed simultaneously. Gas ignition is typically seen at this stage.
(2) The crack is completely closed, and the propping agent is clamped in the crack wall surface under the extrusion action of rock stress, so that the propping agent can be stably fixed at one position.
(3) The oil pressure in this stage goes through a process of dropping and then rising (the well oil pressure with good geological conditions starts rising only when the well oil pressure is reduced to about 2-3 MPa).
(4) The time required for this process varies greatly from a few hours to a dozen hours, depending on the well conditions.
(5) Because of the finger-in effect of the gas, the migration speed of the nitrogen and the natural gas in the cracks and the stratum to the shaft is faster than that of the liquid, the solubility of the gas and the liquid is increased, the amount of gas entering the oil pipe is increased, the spraying potential is increased, the wellhead oil pressure is increased, the fluid is in a gas-liquid mixed state, the outlet is in the spraying potential, and the stage is finished.
In the pressure rising stage, the gas yield and the oil pressure rise are generally faster, a 6-10mm oil nozzle is generally adopted for control on site, and a test flow is introduced for metering and controlling the gas yield and the liquid quantity, and the control blowout in the pressure rising stage is ready for the subsequent production seeking stage.
The pressure rising stage has the following characteristics:
(1) the initial stage is gas-liquid two-phase flow, the middle stage is slug flow (a section of liquid-containing gas is first and a section of gas-containing liquid is second), and the later stage is in mist flow because of the solubility increase of nitrogen and natural gas, so that water columns cannot be formed in the flowing process, and the water columns can only be discharged out of a shaft in mist form under the drive of high-speed air flow.
(2) The oil pressure rises rapidly and approaches stability.
(3) The liquid discharge amount in the stage is obviously smaller than that in the stage of amplifying displacement, and the liquid discharge amount has obvious reduction trend.
(4) After the flowback in this stage is finished, the flowback rate is about 30% and is relatively low.
The well is characterized in that wellhead pressure quickly drops to a very low degree after blowout, then rebounds, but pressure rise is relatively slow, gas yield gradually rises along with the rise of the pressure, when the pressure and the gas yield basically do not rise, the pressure usually shows a steady trend of falling after the production pressure difference is amplified, and the rising amplitude of the gas yield is not large or basically not increased.
As shown in FIG. 5, the middle production well usually has three stages of closed control, amplified discharge capacity and pressure rise in the open-end drainage stage for 1-5 hours, and the production condition is achieved by controlling continuous drainage through a choke and combining the flushing and plugging removal measures of the open-end well excitation.
In the closing control stage, a 3mm oil nozzle is usually selected, the stratum is closed after 1-2 hours, then the oil nozzle is properly enlarged, when the bottom hole pressure is lower than the fracture closing pressure, the fracture is completely closed, the closing control stage is finished, the liquid discharge is controlled by adopting the 5mm oil nozzle after the closing according to the liquid discharge data after the fracture, and the sand discharge phenomenon is avoided under the condition of properly enlarging the oil nozzle.
The amplifying displacement stage is the best time for controlling the liquid discharge of the open-flow nozzle, the quantity of the discharged liquid is relatively large, and the daily liquid discharge quantity is 500m 3 The pressure of the oil pipe can be quickly reduced after the displacement is amplified, the oil pipe can be slowly restored after the pressure is reduced to a certain degree, and the stage is finished. Most intermediate producing wells begin to recover after the wellhead pressure drops to 2-4 Mpa.
Pressure rising stage: the oil pressure is generally reduced greatly after the displacement amplifying stage, and the oil pressure is slowly restored along with the increase of the gas yield, but compared with the gas wells with high yield, the pressure is obviously restored slowly, and the oil pressure of the amplified gas yield is obviously reduced. In general, the oil nozzle is adjusted to observe that the gas yield and the oil pressure are relatively stable, and then the liquid discharge is finished at the stage, namely the production-seeking stage is shifted. The daily liquid discharge amount at this stage is relatively small, and the daily liquid discharge amount is in a descending trend.
The low-yield well is characterized in that the wellhead pressure is quickly reduced to a very low degree, even zero, basically no rebound or rebound to a very low degree after fracturing and open-flow, the liquid discharge amount is also quickly reduced to a very low level along with the pressure reduction, the liquid discharge is difficult, even the liquid cannot be discharged, and the self-injection can be realized by the cooperation of a manual lifting liquid discharge method and the liquid discharge. As shown in FIG. 6, the low-yield well is mainly assisted in drainage by liquid nitrogen gas lift and pumping drainage in the drainage stage, and comprises the following steps:
(1) closing control phase: a 5mm oil nozzle is adopted;
(2) amplifying displacement stage: a 6-12mm oil nozzle is adopted to smoothly discharge liquid;
(3) difficult liquid discharge stage: opening, oil pressure reaches zero, the liquid column pressure of the shaft is equal to the stratum pressure, and draining is stopped;
(4) gas lift and pumping drainage stage: and after induced spraying, the stratum pressure is higher than the liquid column pressure of the shaft, and liquid drainage is carried out.
After the formation is pressed, the sand is discharged from the discharge nozzle, the discharge nozzle can be unevenly dispersed to discharge sand, the unit density is low, a sand line cannot appear at the bottom of the liquid outlet, the size of the oil nozzle is gradually adjusted, the oil nozzle is not too violently controlled, otherwise, the fractured sand body which is discharged from the formation can be restrained from ascending in a shaft, and sedimentation and even sand burying are caused. The most important principle at the stage is to discharge the residual sand in the shaft and inhibit the stratum from continuously spitting sand, and the phenomenon of spitting sand of the stratum is finally eliminated by adopting gradual control measures through on-site observation and change of sand content.
As shown in fig. 7, the mechanism of proppant flowback in the fracture is: the proppants in the artificial fractures are carried into the wellbore by the fracturing fluid or formation fluid under the influence of the formation energy.
The method mainly comprises the following steps of researching and analyzing the proppant return field of the staged fracturing well of the horizontal well in the Erdos area in recent years and the field tracking analysis research of a typical well: (1) the liquid discharge mode after pressing is improper; (2) the crack opening near the shaft or the crack opening of the stratum near the well is larger due to the scouring action of the sand-carrying fluid flowing at high speed; (3) the displacement amount of the fracturing fluid is insufficient, and the propping agent is not completely jacked into the stratum; (4) the fracturing fluid is not thoroughly broken, the viscosity of the fracturing fluid broken residual liquid is high in the process of discharging liquid after fracturing, the capability of wrapping, adsorbing and carrying propping agents is high, and the propping agents become easy to flow under the action of liquid backflow; (5) the proppant is caused to flow back due to improper drainage system.
Aiming at different reasons of sand production of the fracturing well, the following technical measures are provided for effectively preventing the proppant backflow of the fracturing well:
1. optimizing displacement fluid volume for fracturing construction
The crack wall surface near the well shaft of the fracturing well can cause oversized crack opening of a crack opening or a crack opening of a stratum near the well under the etching and scouring effects of sand-carrying fluid flowing at high pressure and high speed, so that the clamping effect of the crack pressure on propping agents is affected. In theory, the use of a sufficient or small excess displacement fluid volume should be an effective means of preventing proppant flowback. Therefore, optimization research of displacement liquid amount is carried out, the displacement liquid amount is properly increased, and the tail propping agent is pushed into the fracture for a certain distance, so that the fracture port has an effective clamping effect on the propping agent.
2. Optimizing gel breaking performance of fracturing fluid
If the fracturing fluid breaks the gel incompletely, then proppant flowback is exacerbated. Under otherwise identical conditions, the higher the viscosity of the gel breaker, the more severe the proppant flowback. To study the influence of the viscosity of the gel breaking solution on the carrying and migration rule of sand, determining a critical viscosity, and under the viscosity, effectively preventing the propping agent from flowing back; the method has the advantages that the crack temperature distribution rule in the construction of the fracturing well is strengthened and researched, and a proper gel breaker adding rule is provided, so that the gel breaking effect of the front, middle and rear sections of the fracturing fluid can be ensured, and particularly, the gel breaking effect of the later construction stage is ensured, and the proppant backflow of the fracturing well is effectively prevented in the aspect of improving the gel breaking thoroughly degree of the fracturing fluid.
3. Reasonably adjusting the gas production working system
During the production process, frequent well switching, plugging removal, blowout opening and the like can cause severe changes in the yield and bottom hole pressure difference, and the yield and bottom hole pressure difference should be properly controlled to reduce and prevent a large amount of backflow of proppants.
4. Fracturing with fiber propping agent
Aiming at the problems of low formation pressure, low flow-back speed of fracturing fluid and low flow-back rate of the Erdos oil and gas field, the flow-back speed of the fracturing fluid is increased while the flow-back pressure of the fracturing fluid is increased in order to increase the flow-back pressure of the fracturing fluid and avoid the backflow of propping agent, and a liquid nitrogen and fiber fracturing high-efficiency flow-back technology is adopted. Because of the special fixity of the fibers, even high-yield gas wells are encountered, the gas well production can be improved without fear of proppant being carried out in large quantities.
The field experiment shows that the stability of the propping agent added with the fiber is greatly improved, which is beneficial to preventing the propping agent from flowing back; the drainage speed is obviously increased by adopting the fiber reinforced fracturing technology, the flowback rate is obviously increased, and the retention injury time of the fracturing fluid is obviously shortened, so that the technology is effective in greatly improving the critical sand-out flow rate of the propping agent, obviously enhancing the stability of the propping agent, realizing the efficient and rapid flowback of the fracturing fluid after fracturing, and avoiding the backflow of the propping agent.
As shown in Table 1, 4 layers of fiber sand fracturing was performed in D66-145 well, and the net fluid amount of the 4 layers of fracturing accumulated into the stratum was 831.2m 3 Sand addition 110m 3 The liquid discharge is only 4 days, and the liquid discharge is 766.3m after pressing 3 The flowback rate of the fracturing fluid is 88.5%, the flowback rate of the fracturing fluid is greatly improved compared with that of the same well, and no propping agent flows back. This demonstrates that fiber fracking has significant advantages.
TABLE 1 fiber frac construction parameters and condition comparison tables
| Parameter/well number | D66-145 | D66-141 | D66-157 |
| Fracturing mode | Fiber fracturing | Conventional fracturing | Conventional fracturing |
| Liquid amount of ground entering net (m) 3 ) | 831.2 | 485.9 | 201.4 |
| Sand adding amount (m) 3 ) | 110 | 77.6 | 34.9 |
| Time to break the gel of shut-in well (min) | 30 | 30 | 30 |
| Glib (mm) | 3、5、6、8、10 | 3、5、8、10 | 3、4、8、10 |
| Flow-back liquid amount (m) 3 ) | 766.3 | 364.35 | 112.8 |
| Flow back rate (%) | 88.5 | 68.6 | 40.9 |
| Post-compression unobstructed flow (×10) 4 m 3 ) | 2.51 | 1.905 | 0.12 |
| Proppant flowback (m) 3 ) | Without any means for | 0.2 | 0.3 |
The purpose of liquid nitrogen companion note in the fracturing construction process is in order to lift liquid effectively, increases the effect of flowing back, and the liquid gas-liquid ratio of flowing back and fusion effect are the key of effective flowing back. In the multistage fracturing construction of the horizontal well, the whole construction time is relatively long, the earlier stage of the fractured layer section can not be returned until the whole construction is completed, the fracturing fluid gel breaking into the ground is completed, the stratum is closed, and the fracturing fluid is gradually separated from the fracturing fluid and further moves upwards along with the conversion of liquid nitrogen into a gaseous state, so that the denitrification phenomenon is formed. Many wells show that the pressure of the well mouth is high on the ground, the nitrogen amount of the liquid discharge port is large, no substantial liquid discharge exists until the nitrogen is exhausted, the pressure falls to zero, at this time, the denitrification liquid starts to go upwards, the effective viscosity does not exist, the liquid discharge amount is gradually reduced, the liquid discharge temperature is also gradually reduced, the liquid ascending speed is slow, and finally the unsuccessful open flow possibly can be caused.
As shown in FIG. 8, on one hand, the liquid nitrogen injection amount can be increased in the first stages of fracturing construction, and the liquid nitrogen injection amount can be reduced step by step in the subsequent stages of fracturing construction, so that liquid nitrogen at the end (point B) of the horizontal well has good lifting effect on the liquid discharge at the upper part (point A) in the liquid discharge process, and the liquid discharge function can be effectively exerted on the upper production zone along with the release of the capacity of the end layer. On the other hand, after the crack is forcedly closed (or the outlet is free from sand, the discharge capacity can be further increased, the upward speed of the denitrification liquid is accelerated, and the possibility of success of one discharge can be improved to a great extent.
The sand accumulation and discharge of the shaft occur in an interval where the horizontal well is not well fractured, namely, sand blocking pump set overpressure occurs or a tool sliding sleeve is not opened, a large amount of sand bodies can be accumulated in the shaft, and then timely sand discharge is needed. The sand bodies cannot be controlled, and are discharged out quickly in time, otherwise sand column pressure is formed in the shaft, and liquid discharge is inhibited. Eventually, the pipe string and the flow are blocked, resulting in a blowout failure. This situation can appear on the ground in two ways: firstly, the bottom of the liquid outlet presents an obvious sand line, the sand ratio is larger and larger, the sand line is thickened gradually, the wellhead pressure is reduced sharply, the size of the oil nozzle is enlarged at a proper signal speed, even the oil nozzle is opened for sand discharge, and the control is resumed after all the sand sections are discharged. Secondly, the sand is blocked up the manifold and blocks up the flow even, well head pressure drops sharply and returns to zero and causes the well to carry out the back pressure, at this moment, should at first steadily open the manifold through valve, observe the apocenosis condition of fluid outlet simultaneously, along with the discharge of a large amount of sand sections, the pressure can rise sharply, the impact force is very big, in order to prevent out of control, can implement the shut-in under the condition of everything.
The sand control and the sand discharge are opposite, and the sand discharge is the same, namely the sand discharge of the stratum is the condition that the stratum is not closed in place, the sand discharge phenomenon exists, and the timely flow control is needed at this time so as to provide the stratum with sufficient closing time, so that a stable drainage channel is formed, and the output efficiency of the stratum is ensured. At this time, the team will gradually decrease the flowback regime (both to expel the sand residue from the well bore and to inhibit the formation from continuing to spit sand). The most important of the stage is on-site observation and test, the liquid discharge condition after the control measures is observed, the change of the sand content is tested, and the formation sand discharge phenomenon is finally eliminated through the gradual control measures.
On the basis of the back flow model after horizontal well pressure, back flow software after horizontal well pressure is compiled, as shown in fig. 9 and 10, and a back flow system after horizontal well pressure is determined by combining the actual situation of back flow after site pressure, as shown in table 2.
Table 2 optimized flowback relationship table between choke diameter and wellhead pressure
| Wellhead oil pressure (MPa) | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 |
| Diameter of oil nozzle (mm) | 3.82 | 3.17 | 2.85 | 2.65 | 2.50 | 2.39 | 2.29 | 2.22 |
| Wellhead oil pressure (MPa) | 9 | 10 | 11 | 12 | 13 | 14 | 15 | 16 |
| Diameter of oil nozzle (mm) | 2.15 | 2.10 | 2.05 | 2.00 | 1.96 | 1.93 | 1.89 | 1.86 |
Drawing a curve schematic diagram of the optimal flowback nozzle diameter under different wellhead pressures as shown in FIG. 11, wherein when the wellhead pressure P is less than or equal to 2MPa, the preferred nozzle diameter is 5mm-6mm; when the pressure of the wellhead is more than or equal to 2MPa and less than or equal to P, the diameter of the oil nozzle is 3mm-4mm; when the pressure of the wellhead is more than or equal to 6MPa and less than or equal to 14MPa, the diameter of the oil nozzle is 2mm-3mm; when the wellhead pressure P is more than 14MPa, the diameter of the oil nozzle is 2mm.
And the ten wells such as DPH-3, DP42H and DPH-15 are subjected to related calculation by the flowback system optimization design software, and are compared with field actual measurement production data, so that the implementation effect is good. The DPH-3 well is specifically analyzed below.
And (3) inputting the calculation parameters shown in the table 3 into the optimal design software of the flow-back system, and performing related calculation.
Table 3 calculation parameter table
The corresponding wellhead pressures were calculated by selecting different diameter nipples as shown in table 4:
table 4 wellhead pressure gauge under different diameter choke
The pressure drop curves for the different diameter choke flowbacks were selected according to table 4 for the DPH-3 wells as shown in fig. 12. Analysis shows that different flowbacks of the oil nozzles are selected, the wellhead pressure drop speeds are different, the larger the diameter of the oil nozzle is, the faster the flowbacks are, and the corresponding wellhead pressure drops faster.
When a flowback oil nozzle is given, the critical flow rate of the fracturing fluid in the crack corresponding to different flowback wellhead pressures can be calculated through the relational expression of the wellhead pressure and the flowback oil nozzle, flowback is respectively carried out through 2mm, 4mm and 6mm oil nozzles, and the corresponding relational curves of the wellhead pressure and the critical flow rate of the fracturing fluid in the crack under different oil nozzles are shown in fig. 13, 14 and 15. It can be seen that in the flowback process, to ensure no sand production, the critical flow velocity V3 calculated by the proppant activation model must be ensured to be greater than the critical flow velocity V2 of the fracturing fluid in the fracture, otherwise, the smaller oil nozzle needs to be replaced.
And (3) calculating the reasonable flowback oil nozzle diameters corresponding to different wellhead pressures according to the critical starting flow rate of the on-site propping agent through a comprehensive model, and drawing a flowback relation chart of the oil nozzle diameters and wellhead pressure optimization.
A 2mm oil nozzle is selected, and various parameters of the DPH-3 well are calculated by using a comprehensive model, and the results are shown in table 5:
table 5 2mm oil nozzle flowback comprehensive model solving data table
Analysis of the data in Table 5 shows that the bottom hole pressure and wellhead pressure decrease with flowback time and that the fracturing fluid filter stall rate decreases rapidly with flowback.
A 4mm oil nozzle is selected, and various parameters of the DPH-3 well are calculated by using a comprehensive model, and the results are shown in table 6:
table 6 data table for solving comprehensive model of 4mm glib flowback
Analysis of Table 6 shows that the bottom hole pressure drop is positively correlated with the wellhead pressure drop, the larger the diameter of the flowback nozzle, the faster the bottom hole pressure drop.
And (4) drawing a bottom hole pressure and flowback time relation graph as shown in fig. 16, and analyzing to show that the bottom hole pressure drop is positively correlated with the wellhead pressure drop, wherein the larger the diameter of a flowback nozzle is, the faster the bottom hole pressure drop is.
From the above analysis, it is known that the flowback system of the fracturing fluid needs to be optimized, and the choke needs to be replaced in time according to the relation curve of the wellhead pressure and the critical flow velocity of the fracturing fluid in the fracture to carry out flowback, as shown in fig. 17, in the process of changing the choke from small to large, the wellhead pressure drops faster and faster.
Claims (6)
1. A method for designing a fracturing flowback system after staged fracturing of a tight gas reservoir horizontal well is characterized by comprising the following steps:
1) Acquiring an initial value of wellhead pressure, and calculating the pressure at the tail end of a shaft through a shaft pressure drop and pipe flow friction pressure drop model;
2) Taking the pressure at the tail end of the shaft as an initial value of the average pressure of the crack, calculating the average pressure of the crack, subtracting the pressure loss in the flowback process from the average pressure of the crack, and calculating the new wellhead pressure;
3) Obtaining a critical flowback flow rate of a propping agent stationary in a crack in a flowback process, and performing forward pushing calculation from a bottom of a well to a wellhead to obtain a fracturing fluid flowback critical flow rate at the wellhead;
4) Determining the diameter of the choke plug to be adopted under the condition of corresponding new wellhead pressure and the current wellhead flowback critical flow rate according to the pre-acquired corresponding relation between wellhead pressure and the wellhead flowback critical flow rate of the fracturing fluid and the diameter of the choke plug;
5) And (3) taking the new wellhead pressure in the step (2) as an initial value of the wellhead pressure, and repeating the steps (1) to 4) until the average fracture pressure reaches the closing pressure.
2. The method for designing the fracturing flowback system after staged fracturing of the tight gas reservoir horizontal well according to claim 1, wherein in the step 5), the correspondence between the wellhead pressure and the drain flow rate and the diameter of the choke is determined by the following method:
and (3) calibrating the flow rate of liquid discharge at the oil nozzle as the flow rate of liquid discharge corresponding to the wellhead pressure and the diameter of the oil nozzle when the oil nozzles with different diameters are adopted for flowback under wellhead pressures with different sizes through experiments.
3. The method for designing a fracturing flow-back system after staged fracturing of a tight gas reservoir horizontal well according to claim 1, wherein in the step 5), the critical flow-back rate of the propping agent when the propping agent is stationary in the fracture is calculated by a fracturing flow-back starting model of the propping agent in the fracture.
4. The method for designing the fracturing flowback system after staged fracturing of the tight gas reservoir horizontal well according to claim 1, wherein in the step 1), the pump stopping pressure when the fracturing fluid stops being injected is used as a wellhead pressure initial value.
5. The method for designing the fracturing flow-back system after staged fracturing of the tight gas reservoir horizontal well according to claim 1, wherein the fracturing stage before the flow-back process adopts fiber propping agent sand fracturing.
6. The method for designing the fracturing flow-back system after staged fracturing of the tight gas reservoir horizontal well according to claim 1, wherein liquid nitrogen is adopted for accompanying injection in a fracturing stage before a flow-back process, the fracturing stage comprises a pre-fracturing stage and a post-fracturing stage, and the injection amount of the liquid nitrogen in the pre-fracturing stage is larger than that in the post-fracturing stage.
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| CN118030005A (en) * | 2024-04-11 | 2024-05-14 | 四川泓腾能源集团有限公司 | Liquid nitrogen fracturing device and use method |
| CN118128489A (en) * | 2024-03-11 | 2024-06-04 | 中国石油天然气股份有限公司 | Fracturing fluid flowback control method and device for coalbed methane well |
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| CN118128489A (en) * | 2024-03-11 | 2024-06-04 | 中国石油天然气股份有限公司 | Fracturing fluid flowback control method and device for coalbed methane well |
| CN118030005A (en) * | 2024-04-11 | 2024-05-14 | 四川泓腾能源集团有限公司 | Liquid nitrogen fracturing device and use method |
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