CN113591421A - Heterogeneous reservoir horizontal well sand liquid production profile dynamic evolution simulation and prediction method - Google Patents

Heterogeneous reservoir horizontal well sand liquid production profile dynamic evolution simulation and prediction method Download PDF

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CN113591421A
CN113591421A CN202111167768.4A CN202111167768A CN113591421A CN 113591421 A CN113591421 A CN 113591421A CN 202111167768 A CN202111167768 A CN 202111167768A CN 113591421 A CN113591421 A CN 113591421A
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董长银
王力智
甘凌云
皇凡生
王卫阳
陈德春
周博
宋雅君
陈琛
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China University of Petroleum East China
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Abstract

The invention discloses a method for simulating and predicting the dynamic evolution of a sand liquid production profile of a horizontal well of a heterogeneous reservoir, which relates to the technical field of oil and gas exploitation engineering. By utilizing the method provided by the invention, the high-speed inflow position of the horizontal well of the heterogeneous reservoir can be quickly identified, the high erosion occurrence position of the sand-control water-control well completion sieve tube is judged, the optimization of the sieve tube structure is guided, the sieve tube with high erosion resistance is used at the high erosion risk position, and the comprehensive erosion resistance of the well completion sieve tube is improved. In addition, the local inflow coefficient provided by the invention can be used for quickly calculating the highest flow speed of the actual local high-speed inflow position for erosion damage rate prediction and prevention.

Description

Heterogeneous reservoir horizontal well sand liquid production profile dynamic evolution simulation and prediction method
Technical Field
The invention relates to the technical field of oil and gas exploitation engineering, in particular to a method for simulating and predicting dynamic evolution of a sand liquid production profile of a horizontal well of a heterogeneous reservoir.
Background
The horizontal well technology is an important technical means for developing petroleum and natural gas, and has the advantages of long production well section (hundreds of meters to thousands of meters), large drainage area, high oil extraction speed and the like. For a horizontal well with loose sandstone and an easily-produced oil and gas reservoir, the exploitation of the horizontal well faces two troublesome problems of sand production and water production. Sand control and water control of long-well-section horizontal wells are one of core technologies for ensuring normal exploitation and production of the long-well-section horizontal wells.
During horizontal well production, it is generally believed or assumed that the feed inflow profile of the reservoir to the horizontal wellbore is uniform. Whether for a high producing gas well (e.g., 200 million square production per day) or an oil well (e.g., 2000 square fluid production per day), the flow rate of fluid to the screens in the wellbore is extremely low, far from an erosive damage condition, if calculated in terms of a horizontal segment uniform inflow. However, a number of field practices have shown that partially sanded wells and horizontal wells exhibit washout damage to the completion screen and that within a limited longer interval, the washout perforation locations are unique, as shown in figure 8. It was concluded that the feed inflow profile of the reservoir to the horizontal well was non-uniform.
Due to the heterogeneity of the cementing strength, permeability and the like of the oil and gas reservoir and the influence of the reservoir on the distribution rule of the porosity and permeability of the reservoir in the sand production process, the change is caused; the change of the porosity and permeability distribution of the reservoir along the axis direction of the shaft can influence the reservoir circulation and inflow profile, and further reversely influence the sand production rule. Namely, a synergistic influence mechanism exists between the formation sand of the heterogeneous sand-prone reservoir and the fluid production profile. The above synergistic influence mechanism causes the sand-liquid inflow profile of the horizontal well of the heterogeneous reservoir to dynamically evolve along with the production time, so that the heterogeneity of sand-liquid inflow becomes stronger and stronger, as shown in fig. 9.
The sand control and water control of horizontal wells of reservoirs easy to produce sand are key technologies for ensuring high-efficiency production. Because the horizontal well production section is long in length, the fluid production section and the sand production section of the horizontal well long production section have heterogeneity caused by the difference of physical properties of reservoirs, and the heterogeneity dynamically evolves along with the production time. The accurate depiction of the sand liquid output section can make sand control and water control operation have a target, and improve the sand control and water control effect. At present, reservoir physical properties are mainly recognized by taking static data measured at the initial development stage as a main part, and a simulation and prediction method is lacked for the dynamic evolution of a sand-liquid production profile of a horizontal well of a heterogeneous reservoir, so that the optimization design of sand and water control measures of the heterogeneous reservoir is lacked with a dynamic basis.
Disclosure of Invention
Aiming at the technical problems, the invention provides a method for simulating and predicting the dynamic evolution of the sand-liquid production section of the horizontal well with the heterogeneous reservoir, and realizes the simulation of the dynamic evolution process of the sand-liquid production section of the horizontal well with the production time with the production section of the heterogeneous reservoir and the prediction of the production section. Finally, the judgment and identification of the horizontal well sand production and water production profile are promoted from the initial static state to the dynamic state, so that effective support is provided for solving the problem of sand and water cooperative control of the long-well-section horizontal well, and the method has general reference value and scientific significance for the dynamic optimization of the horizontal well long-term development mode and the real-time optimization of the single-well production system.
Interpretation of professional terms: the inflow profile comprises a comprehensive inflow coefficient profile, an inflow velocity profile, a sand production intensity profile, a comprehensive inflow coefficient profile, an inflow velocity profile and a sand production intensity profile which are respectively the set of the comprehensive inflow coefficient, the inflow velocity and the sand production intensity of the whole well section at the moment.
The technical scheme for solving the technical problem of the invention is as follows:
the method for simulating and predicting the dynamic evolution of the sand-liquid production profile of the horizontal well of the heterogeneous reservoir comprises the following steps:
s1: carrying out grid division on the horizontal production section of the horizontal well according to the well body structure of the horizontal well and the length of the horizontal production section; calculating to obtain a heterogeneous distribution profile of the cohesive strength, the porosity and the permeability of the reservoir rock according to the initial acoustic time difference, the density and the neutron logging information; performing overall correction on porosity and permeability according to the physical property data of the production horizon test;
in the step S1, carrying out sectional grid division on the horizontal well long production well section by taking delta H (0.2-0.5 m is recommended) as an interval, dividing the horizontal well long production well section into N sections in total, using a serial number i to represent the serial number of any one section, and using i to be more than or equal to 1 and less than or equal to N, as shown in figure 1;
the formula for calculating the cohesive strength of the reservoir rock according to the acoustic time difference and the density logging data is shown as the formula (1):
Figure 373252DEST_PATH_IMAGE001
(1)
in the formula (I), the compound is shown in the specification,
Figure 811317DEST_PATH_IMAGE002
the cohesive strength of the rock at the jth logging depth is MPa; sigmacThe uniaxial compressive strength of the rock is MPa; rhorIs the density of stratum rock in kg/m3；∆thIs the transverse wave time difference, mu s/m; Δ tvIs the longitudinal wave time difference, mu s/m;
the formula for calculating the porosity of the reservoir according to the neutron logging data is shown in the formulas (2) and (3):
Figure 342793DEST_PATH_IMAGE003
(2)
Figure 279525DEST_PATH_IMAGE004
(3)
in the formula (I), the compound is shown in the specification,
Figure 984176DEST_PATH_IMAGE005
is neutron porosity, dimensionless;
Figure 11169DEST_PATH_IMAGE006
is the density of the rock skeleton in g/cm3;
Figure 510283DEST_PATH_IMAGE007
Is the density of the water of the stratum in g/cm3;
Figure 137574DEST_PATH_IMAGE008
The mud content is dimensionless;
Figure 673946DEST_PATH_IMAGE009
is the density of mud in g/cm3;
Figure 70292DEST_PATH_IMAGE010
The initial porosity is obtained by calculation, and the method is dimensionless;
Figure 740308DEST_PATH_IMAGE011
density porosity, dimensionless; general sandstone reservoir
Figure 120473DEST_PATH_IMAGE012
Respectively taking 2.65, 1 and 2.42.
The calculation formula for calculating the reservoir permeability is shown in (4):
Figure 652080DEST_PATH_IMAGE013
(4)
wherein k is permeability, mD; swiTo restrict water saturation, noneDimension.
Defining the porosity correction coefficient and the permeability correction coefficient as follows: the ratio of the average porosity and permeability of the reservoir calibrated by reservoir oil reservoir engineering to the average porosity and permeability of the non-uniform profile calculated according to the logging data is calculated by the following steps (5) and (6):
Figure 371774DEST_PATH_IMAGE014
(5)
Figure 212691DEST_PATH_IMAGE015
(6)
in the formula
Figure 80153DEST_PATH_IMAGE016
The porosity correction coefficient and the permeability correction coefficient are respectively dimensionless;
Figure 664718DEST_PATH_IMAGE017
the average porosity and permeability of the reservoir are respectively calibrated for reservoir oil reservoir engineering, and the units are respectively decimal (dimensionless) and mD;
Figure 238919DEST_PATH_IMAGE018
respectively calculating the initial porosity and permeability of the jth logging depth according to the logging information and the formulas (3) and (4), wherein the units are decimal (dimensionless) and mD; and M is the logging data quantity and is dimensionless.
Correcting non-uniform distribution data of porosity and permeability obtained according to logging data according to the average porosity and permeability of a reservoir layer calibrated by oil reservoir engineering, wherein the non-uniform distribution data are shown as formulas (7) and (8):
Figure 1470DEST_PATH_IMAGE019
(7)
Figure 90649DEST_PATH_IMAGE020
(8)
in the formula，
Figure 478905DEST_PATH_IMAGE021
The corrected initial porosity of the jth logging depth is dimensionless;
Figure 907612DEST_PATH_IMAGE022
initial permeability, mD, for corrected jth log depth;
definition of
Figure 90332DEST_PATH_IMAGE023
Is the average porosity of the i well section, is dimensionless, and is calculated by the method that the i well section ranges
Figure 683118DEST_PATH_IMAGE024
Is calculated as the arithmetic mean of (1).
S2: fitting and calculating an average oil-production-simulated index, a gas-production-simulated index and a water-production-simulated index according to the yield, the permeability, the length of the production section and the production pressure difference of the horizontal well; calculating inflow intensity distribution of the horizontal section according to the uniform inflow situation of the production section; calculating the flow pressure drop of the horizontal section and the wellbore pressure of each grid section according to the inflow intensity distribution of the horizontal section, the static pressure of the stratum and the bottom hole flow pressure of the toe end;
preferably, in step S2, the pseudo oil recovery/water/gas index is defined and calculated as shown in formulas (9), (10), (11), respectively:
Figure 609486DEST_PATH_IMAGE025
(9)
Figure 892700DEST_PATH_IMAGE026
(10)
Figure 777479DEST_PATH_IMAGE027
(11)
in the formula (I), the compound is shown in the specification,
Figure 575671DEST_PATH_IMAGE028
in order to average the pseudo-oil-production index,
Figure 243412DEST_PATH_IMAGE029
；
Figure 194182DEST_PATH_IMAGE030
m is the oil production of the horizontal well3/d;k0Reservoir average permeability, mD, calibrated for reservoir engineering; l ishM is the length of a horizontal well production section;
Figure 984284DEST_PATH_IMAGE031
production differential pressure, MPa;
JXWis an average pseudo-water sampling index, m2/（N·s）；QwM is the water yield of the horizontal well3/d;
JxgIs an average pseudo-gas production index, m2/（N·s）；QgFor gas production of horizontal wells, m3/d。
Initializing the inflow intensity of the shaft according to the uniform inflow profile of the whole well, and using the intensity to calculate the pressure distribution of the shaft, wherein the calculation formula of the actual bottom hole flow pressure of each well section of the horizontal section is shown as the formula (12):
Figure 269771DEST_PATH_IMAGE032
(12)
in the formula, Pwf(i)The actual bottom hole flowing pressure of the ith well section is MPa, when i =1,
Figure 803521DEST_PATH_IMAGE033
to calibrate the bottom hole flow pressure;
Figure 61327DEST_PATH_IMAGE034
the flow pressure loss per unit length of the ith well section is MPa/m;
Figure 773062DEST_PATH_IMAGE035
and (4) calculating according to a flow friction pressure drop formula to obtain the actual wellbore flow of the ith wellbore section, wherein the actual wellbore flow of the ith wellbore section is the sum of all grid inflow flows from the wellbore section to the toe end.
S3: subtracting the wellbore pressure by using the formation static pressure to obtain the reservoir inflow production pressure difference of each grid section; calculating the inflow intensity of oil, gas and water of the grid section according to the oil-production-simulated index, the gas-production-simulated index and the water-production-simulated index to form an initial inflow profile;
preferably, in step S3, the calculation formula of the actual production pressure difference of each well section of the horizontal section is as shown in formula (13):
Figure 545846DEST_PATH_IMAGE036
(13)
in the formula, Pr-formation static pressure, MPa;
Figure 820970DEST_PATH_IMAGE037
actual differential pressure in production, MPa, at point i.
The volume calculation formula of the reservoir rock framework of each well section is shown as the formula (14):
Figure 730020DEST_PATH_IMAGE038
(14)
in the formula, TV(i)Is the volume of the rock skeleton of the reservoir at the ith well section, m3；RwIs the wellbore radius, m; rmThe formation sand radius, m.
The fluid inflow intensity calculation formula is shown in formulas (15), (16), (17) and (18):
Figure 127503DEST_PATH_IMAGE039
(15)
Figure 872736DEST_PATH_IMAGE040
(16)
Figure 951551DEST_PATH_IMAGE041
(17)
Figure 246266DEST_PATH_IMAGE042
(18)
in the formula, Qo(i)Oil inflow intensity at i-section, m3/(d·m）；Qw（i）Water inflow intensity at section i, m3/（d·m）；Qg（i）Intensity of gas inflow at section i, m3/（d·m）；Ql(i)Intensity of fluid inflow at segment i, m3/（d·m）；k（i）All k in i well section0jAverage value of (d);
the total flow rate calculation is shown in equation (19):
Figure 283492DEST_PATH_IMAGE043
(19)
Vf(i)the fluid inflow velocity is m/min; dwIs the wellbore diameter, m.
S4: calculating the sand production rate and the sand concentration according to the inflow velocity of the fluid of each grid section and the cohesive strength of the rock to form a sand production strength non-uniform distribution profile; calculating a comprehensive inflow coefficient to obtain a comprehensive inflow non-uniform section;
preferably, in step S4, V at each section of the whole well section is calculatedf(i)S with each log depth0jAnd then calculating the average value through the whole well section to obtain the average fluid inflow velocity VfaAnd average cohesive strength S0aSaid V isfa、S0aEach of V of the whole well sectionf(i)And S0jIs calculated as the arithmetic mean of (1).
The calculation formula of the simulated sand index is shown as the formula (20):
Figure 30868DEST_PATH_IMAGE044
(20)
in the formula, JxsTo draw up a sand index, m/s; l isqsThe sand production strength is L/(d.m); u shapefFluid viscosity, mpa.s.
Calculating the sand production rate and the sand concentration according to the inflow conditions, as shown in the formula (21):
Figure 647794DEST_PATH_IMAGE045
(21)
Qs（i）the sand production rate at the well section i is L/(d.m); s0（i）Average cohesive strength of the ith interval, total S in the ith interval0jAverage value of (d);
the sand content calculation formula is shown as formula (22):
Figure 282169DEST_PATH_IMAGE046
(22)
Cs（i）the sand concentration at the well section i is dimensionless.
The integrated inflow coefficient calculation formula is shown in equation (23):
Figure 755876DEST_PATH_IMAGE047
(23)
in the formula, Z（i）The comprehensive inflow coefficient is dimensionless; qsaThe average sand production rate, L/(d.m), for the entire interval is calculated for each interval
Figure 724969DEST_PATH_IMAGE048
The average value is calculated.
S5: drawing a non-uniform distribution profile diagram of indexes such as horizontal section reservoir rock cohesive strength, porosity, permeability, oil-gas-water inflow strength, sand production strength, liquid sand content, comprehensive inflow index and the like in an initial production state;
preferably, in step S5, the horizontal well depth is taken as the horizontal axis, and indexes such as the cohesive strength, porosity, permeability, inflow strength of oil, gas and water, sand production strength, liquid sand content, and comprehensive inflow index of reservoir rock at each interval of the horizontal well are taken as the vertical axis, and the non-uniform distribution profile line graph is drawn by taking fig. 2 as an example.
S6: setting the production time Δ t. And calculating the inflow indexes and the distribution thereof on each grid section after the time t on the basis of the non-uniform inflow profile of each index at the initial time (t = 0). Calculating the sand yield of each grid section in the time period of the Δ t, and calculating the porosity change of the reservoir and the porosity, permeability and cohesive strength after the change according to the sand yield of each grid section of the well section;
according to the invention, in the step S6, the accumulated sand yield of the i well section grid within the Δ t time is preferably calculated as shown in formula (24):
Figure 145586DEST_PATH_IMAGE049
(24)
in the formula,. DELTA.Vs（i）The i well section accumulated sand yield m within t time3。
Calculating the porosity at the end of the time when the sand is discharged according to the sand discharge amount, wherein the calculation formula is shown as the formula (25):
Figure 149314DEST_PATH_IMAGE050
(25)
in the formula (I), the compound is shown in the specification,
Figure 544654DEST_PATH_IMAGE051
the porosity of the near-well stratum at the end of the time t of the i well section is dimensionless;
Figure 1043DEST_PATH_IMAGE052
the porosity of the near well stratum at the time of i well section Δ t is dimensionless. In the first iteration of the process,
Figure 959772DEST_PATH_IMAGE053
equal to that calculated in step S1
Figure 818007DEST_PATH_IMAGE054
In each iteration cycle after the first time, each is at the first time
Figure 899095DEST_PATH_IMAGE053
At the end of one Δ t
Figure 327934DEST_PATH_IMAGE055
The calculation result of (2);
the calculation formula of the parameters of the porosity, permeability and cohesive strength variation amplitude is shown in the formulas (26), (27) and (28):
Figure 90353DEST_PATH_IMAGE056
(26)
Figure 803094DEST_PATH_IMAGE057
(27)
Figure 55084DEST_PATH_IMAGE058
(28)
Figure 486065DEST_PATH_IMAGE059
the i well section porosity change rate amplitude parameter at the end of t time is dimensionless;
Figure 786597DEST_PATH_IMAGE060
the i well section permeability change rate amplitude parameter at the end of the t time is dimensionless;
Figure 104577DEST_PATH_IMAGE061
and the cohesive strength change rate amplitude parameter of the i well section at the end of the t time is dimensionless.
And (3) calculating the permeability change, and according to the conversion of the porosity change ratio, calculating the formula as shown in formula (29):
Figure 527468DEST_PATH_IMAGE062
(29)
in the formula, k（i,t1）The near-well stratum permeability at the end of the time at the i well section, mD; k is a radical of（i,t0）For the initial near-well permeability at the time of Δ t for the i-well section, mD, in the first iteration, k（i,t0）K equal to that calculated in step S3（i）In each iteration cycle after the first time, each is at the first time
Figure 383428DEST_PATH_IMAGE063
Equal to one at end（i,t1）The calculation result of (2);
calculating the change of cohesive strength as shown in formula (30):
Figure 81126DEST_PATH_IMAGE064
(30)
in the formula, S0（i，t1）The cohesive strength of the near-well stratum at the end of the time of i well section is MPa; s0（i，t0）The cohesive strength of the near-well stratum at the time of the arrival of the i well section, MPa, S in the first iteration0（i，t0）Is equal to S calculated in step S40（i）In each iteration cycle after the first time, S at each time t0（i，t0）Equal to S at the end of one0（i，t1）The calculation result of (2);
s7: recalculating pressure distribution of each grid section of a well bore of the production section according to an inflow profile at the initial time (t = 0), and subtracting the pressure of the well bore by using formation static pressure to obtain reservoir inflow production differential pressure of each grid section; calculating the inflow intensity of oil, gas and water of a new grid section according to the porosity and permeability at the time t to form a new inflow profile;
preferably, in step S7, the wellbore pressure distribution is calculated by using the wellbore inflow intensity of each well section at the initial time (t = 0). The calculation formula of the actual bottom hole flowing pressure of each point of the horizontal section is shown as the formula (31)
Figure 519192DEST_PATH_IMAGE065
(31)
In the formula, Pwf（i，t1）The actual bottom hole flowing pressure of the ith well section at the end of delta t is MPa; pwf（i-1，t1）The actual bottom hole flow pressure of the i-1 th well section at the end of delta t is Mpa; delta Pk（i，t1）The flow pressure loss per unit length of the ith well section at the end of time delta t is MPa/m. Delta Pk（i，t1）In order to obtain the flow friction pressure drop formula calculation according to the inflow at the initial time (t = 0),the actual wellbore flow of the ith well section is the sum of all grid inflow rates from the well section to the toe end;
the calculation formula of the actual production pressure difference of each well section of the horizontal section is shown as the formula (32):
Figure 50667DEST_PATH_IMAGE066
(32)
in the formula,. DELTA.P（i，t1）The actual production pressure difference of the ith well section at the end of the time delta t is MPa.
The fluid output speed calculation formula at the time of Δ t is shown as the formulas (33), (34), (35) and (36):
Figure 190661DEST_PATH_IMAGE067
in the formula, Qo(i,t1)The oil inflow intensity at i well section at the end of time delta t, m3/（d·m）；Qw(i,t1)Water inflow intensity at i well section at end of time Δ t, m3/（d·m）；Qg(i,t1)The gas inflow intensity at i well section at the end of time Δ t, m3/（d·m）；Ql(i,t1)The fluid inflow intensity at i well section at the end of time at, m3/（d·m）；k(i,t1)The average value of each permeability at the i well section at the end of the time delta t is shown.
The total flow rate calculation is shown in equation (37):
Figure 895312DEST_PATH_IMAGE068
(37)
Vf(i,t1)the fluid inflow velocity at the i well section at the end of the time delta t is m/min; da is the diameter of the well shaft at the well section i and m.
S8: calculating the sand output, sand content and comprehensive inflow index of each new grid section according to the new inflow strength and cohesion strength at the time t to obtain a new non-uniform distribution profile of all inflow indexes at the time t;
preferably, in step S8, the average inflow velocity and the cohesive strength of the whole wellbore section are calculated to obtain the end of the Δ t timeAverage fluid inflow velocity Vfa(t1)And average cohesive strength S0a(t1)，Vfa(t1)And S0a(t1)V of all well sections respectivelyf(i,t1)And S0(i,t1)Is calculated as the arithmetic mean of (1).
The sand production index calculation formula is shown as the formula (38):
Figure 640414DEST_PATH_IMAGE069
(38)
in the formula, Jxs(t1)The sand index at the time of t. L isqsThe sand production strength is L/(d.m); u shapefFluid viscosity, mpa.s.
Calculating the sand production rate and the sand concentration according to the inflow conditions, as shown in the formula (39):
Figure 139529DEST_PATH_IMAGE070
(39)
Qs(i,t1)the sand production rate at the i well section at the time t is L/(d.m).
The sand content calculation formula is shown as the formula (40):
Figure 783131DEST_PATH_IMAGE071
(40)
Cs(i,t1)the sand concentration at the i well section at the end of the delta t time is dimensionless.
The integrated inflow coefficient calculation formula is shown as equation (41):
Figure 25893DEST_PATH_IMAGE072
(41)
in the formula, Z(i,t1)The comprehensive inflow coefficient at the i well section at the end of the delta t time is dimensionless; qsa(t1)Average sand production rate of whole well section at delta t time, L/(d.m), Q for whole well sections(i,t1)And (6) taking an average value.
S9: a local Inflow coefficient (PIF coefficient for short) is calculated.
Preferably, in step S9, the PIF coefficient calculation formula is represented by equations (42) and (43):
Figure 891081DEST_PATH_IMAGE073
in the formula, PIFsThe local inflow coefficient of the sand production strength is dimensionless; PIFlThe local inflow coefficient is the liquid production intensity, and is dimensionless; qsmax(t1)The highest sand production rate of the whole well section at the end of time delta t, L/(d.m), Vfmax(t1)The maximum fluid inflow velocity of the whole well section at the end of the time delta t, m/min, and Q at each point of the whole wells(i,t1)And Vf(i,t1)The highest value is taken.
S10: and the production time is increased by Δ t, the iterative calculation of the next time step is continued from S6, the dynamic evolution of the sand liquid production profile is realized circularly, and various inflow profile predictions at any time t are realized.
The invention has the beneficial effects that:
1. the sand control and water control of horizontal wells of reservoirs with easy sand production are key technologies for ensuring high-efficiency production, and due to the lack of a simulation and prediction method for the dynamic evolution of the sand liquid production profile of horizontal wells of heterogeneous reservoirs, the sand control and water control measures of the horizontal wells of heterogeneous reservoirs are lack of purpose. By utilizing the method provided by the invention, the evolution process of the sand liquid production profile can be simply and rapidly simulated, the stratum fluids (oil, gas and water) and the stratum sand production profile under given production conditions and production time can be predicted, and key production positions are provided for the design of the horizontal well sand control and water control tubular columns, namely key control well sections and positions, so that the purposes and comprehensive effects of sand control and water control are provided.
2. By utilizing the method provided by the invention, the high-speed inflow position of the horizontal well of the heterogeneous reservoir can be quickly identified, the high erosion occurrence position of the sand-control water-control well completion sieve tube is judged, the optimization of the sieve tube structure is guided, the sieve tube with high erosion resistance is used at the high erosion risk position, and the comprehensive erosion resistance of the well completion sieve tube is improved. In addition, the local inflow coefficient (PIF coefficient) provided by the invention can be used for quickly calculating the highest flow speed of an actual local high-speed inflow position for erosion damage rate prediction and prevention.
3. The method provided by the invention promotes the judgment and identification of the sand production and water production profile of the horizontal well from static state to dynamic state, and provides effective support for solving the problem of sand-water cooperative control of the horizontal well at a long well section; compared with static sand-water profile identification, the sand control efficiency is greatly improved. And parameter design basis can be provided for the intelligent sand and water control device, more reasonable sand and water outlet intervention can be carried out along with the production change of the stratum, the possible condition of a large amount of sand/water outlet of the oil well in the future can be avoided at the lowest cost, and the remedial operation after sand and water outlet and the excessive sand prevention of a slight sand outlet well section can be avoided. The method has general reference value and scientific significance for dynamic optimization of a long-term development mode of an oil and gas reservoir, real-time optimization of a single-well production system and dynamic adjustment of a recovery efficiency improving mode.
Drawings
FIG. 1 is a schematic diagram of a method for calculating evolution of a dynamic profile produced by heterogeneous sand liquid;
FIG. 2 is a heterogeneous cross-sectional view of the initial porosity of a horizontal well;
FIG. 3 is a schematic diagram of the dynamic evolution distribution of the porosity of a horizontal well;
FIG. 4 is a schematic diagram of the dynamic evolution distribution of permeability of a horizontal well;
FIG. 5 is a schematic diagram of dynamic evolution distribution of a comprehensive inflow coefficient of a horizontal well;
FIG. 6 is a schematic diagram of the dynamic evolution distribution of inflow velocity of a horizontal well;
FIG. 7 is a schematic diagram of the dynamic evolution distribution of sand production intensity of a horizontal well;
FIG. 8 is a schematic diagram of non-uniform inflow of a horizontal well;
FIG. 9 is a schematic diagram of the dynamic evolution of a horizontal well sand fluid production profile of a heterogeneous reservoir.
Detailed Description
In order to clearly explain the technical features of the present invention, the following detailed description of the present invention is provided with reference to the accompanying drawings. The following disclosure provides many different embodiments, or examples, for implementing different features of the invention. To simplify the disclosure of the present invention, the components and arrangements of specific examples are described below. Furthermore, the present invention may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. It should be noted that the components illustrated in the figures are not necessarily drawn to scale. Descriptions of well-known components and processing techniques and procedures are omitted so as to not unnecessarily limit the invention.
The simulation and prediction method for the dynamic evolution of the sand liquid production profile of the horizontal well with the heterogeneous reservoir is applied to the horizontal section of the horizontal well with a certain oil reservoir in the victory oil field, the horizontal section of the horizontal well is 685m long, the water content is 95%, the liquid production amount is about 97t/D, the sand content of the fluid volume is 0.01%, the viscosity of degassed crude oil is 400mPa.s, the average permeability of the stratum is 0.4D, and the porosity is 33%. By using the method, the porosity, the permeability, the comprehensive inflow index, the inflow speed and the sand production intensity of a horizontal segment are predicted and obtained by taking 5 years as the total calculation time and taking 30 days as the single calculation step length, and the dynamic evolution distribution schematic diagrams are shown in fig. 3 to 7.
According to the dynamic evolution prediction result of the output section, stratum particles are peeled off along with the production process, and the porosity and the permeability are integrally and gradually increased and gradually accelerated. The pore permeability change is obvious at 950-1100 m, and the increase range of the porosity and the permeability has obvious positive correlation with the initial physical property. Along with the continuous production process, the inflow speed and the sand production strength are gradually enhanced, areas with high sand production and high permeability are at 950 + 1100 m, 1480 m and 1580 m, and the sand production and the water production have obvious enhancement tendency. And because of the difference between the formation physical properties and the production pressure difference, the overlapping degree of the initial sand production and water production profiles is lower, and the initial sand production and water production profiles gradually tend to overlap along with the production continuation, which shows that the sand production and the water production converge with each other. According to the preliminary simulation result, the inflow speed and the sand output intensity of the high-speed inflow point are increased by 4-6 times, and the sand output intensity of the area is higher than that of other areas by more than 8 times, so that the area is a key sand prevention and erosion prevention object.
Although the embodiments of the present invention have been described with reference to the accompanying drawings, the scope of the present invention is not limited thereto, and various modifications and variations which do not require inventive efforts and which are made by those skilled in the art are within the scope of the present invention.

Claims (3)

1. The method for simulating and predicting the dynamic evolution of the sand-liquid production profile of the horizontal well of the heterogeneous reservoir is characterized by comprising the following steps of:
s1: according to the well body structure and the length of the horizontal production section of the horizontal well, carrying out grid division on the horizontal production section of the horizontal well:
carrying out sectional grid division on the long production well section of the horizontal well at intervals of delta H, wherein the horizontal well is divided into N sections in total, the serial number of any one section is represented by a serial number i, and i is more than or equal to 1 and less than or equal to N;
calculating to obtain a heterogeneous distribution profile of the cohesive strength, the porosity and the permeability of the rock according to the initial acoustic time difference, the density and neutron logging data:
the formula for calculating the cohesive strength of the reservoir rock according to the acoustic time difference and the density logging data is shown as the formula (1):
Figure 442634DEST_PATH_IMAGE001
(1)
in the formula (I), the compound is shown in the specification,
Figure 624348DEST_PATH_IMAGE002
the cohesive strength of the rock at the jth logging depth is MPa; sigmacThe uniaxial compressive strength of the rock is MPa; rhorIs the density of stratum rock in kg/m3；∆thIs the transverse wave time difference, mu s/m; Δ tvIs the longitudinal wave time difference, mu s/m;
the formula for calculating the neutron porosity of the reservoir according to the neutron logging data is shown in the formulas (2) and (3):
Figure 721617DEST_PATH_IMAGE003
(2)
Figure 554444DEST_PATH_IMAGE004
(3)
in the formula (I), the compound is shown in the specification,
Figure 711756DEST_PATH_IMAGE005
is neutron porosity, dimensionless;
Figure 380766DEST_PATH_IMAGE006
is the density of the rock skeleton in g/cm3;
Figure 281726DEST_PATH_IMAGE007
Is the density of the water of the stratum in g/cm3;
Figure 703480DEST_PATH_IMAGE008
The mud content is dimensionless;
Figure 31693DEST_PATH_IMAGE009
is the density of mud in g/cm3;
Figure 922420DEST_PATH_IMAGE010
The initial porosity is obtained by calculation, and the method is dimensionless;
Figure 627070DEST_PATH_IMAGE011
density porosity, dimensionless;
the calculation formula for calculating the reservoir permeability is shown in (4):
Figure 168910DEST_PATH_IMAGE012
(4)
wherein k is permeability, mD; swiDimensionless for irreducible water saturation;
and (3) performing overall correction on porosity and permeability according to the physical property data of the production horizon test:
defining the ratio of the porosity correction coefficient and the permeability correction coefficient to the average porosity and permeability of the reservoir calibrated by reservoir oil deposit engineering and the average porosity and permeability of the non-uniform profile calculated according to logging data, and calculating by using the following steps (5) and (6):
Figure 668025DEST_PATH_IMAGE013
(5)
Figure 498577DEST_PATH_IMAGE014
(6)
in the formula
Figure 492072DEST_PATH_IMAGE015
The porosity correction coefficient and the permeability correction coefficient are respectively dimensionless;
Figure 153998DEST_PATH_IMAGE016
the average porosity and permeability of the reservoir are respectively calibrated for reservoir oil reservoir engineering, and the units are respectively decimal (dimensionless) and mD;
Figure 824014DEST_PATH_IMAGE017
respectively calculating the initial porosity and permeability of the jth logging depth point obtained according to the logging information and the logging information (3) and (4), wherein the units are decimal dimensionless and mD; m is the logging data quantity and is dimensionless;
correcting non-uniform distribution data of porosity and permeability obtained according to logging data according to reservoir average porosity and permeability calibrated by reservoir engineering, as shown in (7) and (8):
Figure 938600DEST_PATH_IMAGE018
(7)
Figure 922737DEST_PATH_IMAGE019
(8)
in the formula (I), the compound is shown in the specification,
Figure 189901DEST_PATH_IMAGE020
to be corrected toInitial porosity for j log depths, dimensionless;
Figure 296397DEST_PATH_IMAGE021
initial permeability, mD, for corrected jth log depth;
definition of
Figure 101542DEST_PATH_IMAGE022
Is the average porosity of the i well section, is dimensionless, and is calculated by the method that the i well section ranges
Figure 686107DEST_PATH_IMAGE023
An arithmetic mean;
S2：
fitting and calculating an average oil-production-simulated index, a gas-production-simulated index and a water-production-simulated index according to the yield, the permeability, the length of the production section and the production pressure difference of the horizontal well; calculating the flow pressure drop of the horizontal section and the wellbore pressure of each grid section according to the inflow intensity distribution of the horizontal section, the static pressure of the stratum and the bottom hole flow pressure of the toe end;
the average pseudo oil recovery/water/gas index is calculated using equations (9), (10), (11), respectively:
Figure 57046DEST_PATH_IMAGE024
(9)
Figure 616334DEST_PATH_IMAGE025
(10)
Figure 439934DEST_PATH_IMAGE026
(11)
in the formula (I), the compound is shown in the specification,
Figure 31452DEST_PATH_IMAGE027
in order to average the pseudo-oil-production index,
Figure 256897DEST_PATH_IMAGE028
；
Figure 190349DEST_PATH_IMAGE029
m is the oil production of the horizontal well3K0 is the reservoir average permeability, mD, calibrated by reservoir oil deposit engineering; l ishM is the length of a horizontal well production section;
Figure 32403DEST_PATH_IMAGE030
production differential pressure, MPa;
JXWis an average pseudo-water sampling index, m2/（N·s）；QwM is the water yield of the horizontal well3/d;
JxgIs an average pseudo-gas production index, m2/（N·s）；QgFor gas production of horizontal wells, m3/d；
Initializing the inflow intensity of the shaft according to the uniform inflow profile of the whole well, and using the intensity to calculate the pressure distribution of the shaft, wherein the calculation formula of the actual bottom hole flow pressure of each well section of the horizontal section is shown as the formula (12):
Figure 693192DEST_PATH_IMAGE031
(12)
in the formula, Pwf(i)The actual bottom hole flowing pressure of the ith well section is MPa, when i =1,
Figure 320613DEST_PATH_IMAGE032
to calibrate the bottom hole flow pressure;
Figure 674234DEST_PATH_IMAGE033
the flow pressure drop per unit length of the ith well section is MPa/m;
Figure 472426DEST_PATH_IMAGE034
calculating according to a flow friction resistance pressure drop formula;
S3：
subtracting the actual wellbore pressure of each well section by using the formation static pressure to obtain the reservoir inflow production pressure difference of each grid section; calculating the inflow intensity of oil, gas and water of the grid section according to the oil-production-simulated index, the gas-production-simulated index and the water-production-simulated index to form an initial inflow profile:
the calculation formula of the actual production pressure difference of each well section of the horizontal section is shown as the formula (13):
Figure 202485DEST_PATH_IMAGE035
(13)
in the formula (I), the compound is shown in the specification,
Figure 153254DEST_PATH_IMAGE036
-actual differential production pressure, MPa, at point i; pr-formation static pressure, MPa;
the volume calculation formula of the reservoir rock framework of each well section is shown as the formula (14):
Figure 943356DEST_PATH_IMAGE037
(14)
in the formula, TV(i)Is the volume of the rock skeleton of the reservoir at the ith well section, m3；RwIs the wellbore radius, m; rmThe formation sand production radius, m;
the fluid inflow intensity calculation formula is shown in formulas (15), (16), (17) and (18):
Figure 432106DEST_PATH_IMAGE038
(15)
Figure 965855DEST_PATH_IMAGE039
(16)
Figure 754820DEST_PATH_IMAGE040
(17)
Figure 540591DEST_PATH_IMAGE041
(18)
in the formula, Qo(i)Oil inflow intensity at i-section, m3/(d·m）；Qw（i）Water inflow intensity at section i, m3/（d·m）；Qg（i）Intensity of gas inflow at section i, m3/（d·m）；Ql(i)Intensity of fluid inflow at segment i, m3/（d·m）；k（i）All k in i well section0jAverage value of (d);
the total flow rate calculation is shown in equation (19):
Figure 47795DEST_PATH_IMAGE042
(19)
Vf(i)the fluid inflow velocity is m/min; dwIs the wellbore diameter, m;
S4：
calculating the sand production rate and the sand concentration according to the inflow velocity of the fluid of each grid section and the cohesive strength of the rock to form a sand production strength non-uniform distribution profile; calculating a comprehensive inflow coefficient to obtain a comprehensive inflow non-uniform section:
calculating V at each section of the whole wellbore sectionf(i)S with each log depth0jAnd then calculating the average value through the whole well section to obtain the average fluid inflow velocity VfaAnd average cohesive strength S0aSaid V isfa、S0aEach of V of the whole well sectionf(i)And S0jThe arithmetic mean of (a):
the calculation formula of the simulated sand index is shown as the formula (20):
Figure 667127DEST_PATH_IMAGE043
(20)
in the formula, JxsTo draw up a sand index, m/s; l isqsThe sand production strength is L/(d.m); u shapefFluid viscosity, mpa.s;
calculating the sand production rate and the sand concentration according to the inflow conditions, as shown in the formula (21):
Figure 576177DEST_PATH_IMAGE044
(21)
Qs（i）the sand production rate at the well section i is L/(d.m); s0（i）Average cohesive strength of the ith interval, total S in the ith interval0jAverage value of (d);
the sand content calculation formula is shown as formula (22):
Figure 442502DEST_PATH_IMAGE045
(22)
Cs（i）the sand concentration at the well section i is dimensionless;
the integrated inflow coefficient calculation formula is shown in equation (23):
Figure 453314DEST_PATH_IMAGE046
(23)
in the formula, Z（i）The comprehensive inflow coefficient is dimensionless; qsaThe average sand production rate for the whole interval, L/(d.m), is Q for each intervals（i）Calculating an average value;
s5: drawing a non-uniform distribution profile diagram of indexes such as horizontal section reservoir rock cohesive strength, porosity, permeability, oil-gas-water inflow strength, sand production strength, liquid sand content, comprehensive inflow index and the like in the production state at the initial time (t = 0): drawing a non-uniform distribution profile broken line graph by taking the well depth of the horizontal well as a horizontal coordinate and taking indexes such as the cohesive strength, porosity, permeability, oil-gas-water inflow strength, sand production strength, liquid sand content, comprehensive inflow index and the like of reservoir rock of each well section of the horizontal well as a vertical coordinate;
s6: setting the production time step Δ t, calculating the inflow indexes and distribution thereof on each grid section after the time t on the basis of the non-uniform inflow profile of each index at the initial time (t = 0), and calculating the porosity change of the reservoir and the porosity, permeability and cohesive strength after the change according to the sand output of each grid section of the well section:
the sand output of each grid section in the time t period is calculated firstly, the accumulated sand output of the i well section grid in the time t is calculated according to the formula (24):
Figure 328866DEST_PATH_IMAGE047
(24)
in the formula,. DELTA.Vs（i）The i well section accumulated sand yield m within t time3；
Calculating the porosity at the end of the time when the sand is discharged according to the sand discharge amount, wherein the calculation formula is shown as the formula (25):
Figure 561264DEST_PATH_IMAGE048
(25)
in the formula (I), the compound is shown in the specification,
Figure 598491DEST_PATH_IMAGE049
the porosity of the near-well stratum at the end of the time t of the i well section is dimensionless;
Figure 611446DEST_PATH_IMAGE050
the porosity of the near well stratum at the time of the i well section Δ t is dimensionless; in the first iteration of the process,
Figure 775842DEST_PATH_IMAGE051
equal to that calculated in step S1
Figure 862747DEST_PATH_IMAGE052
；
The calculation formula of the parameters of the porosity, permeability and cohesive strength variation amplitude is shown in the formulas (26), (27) and (28):
Figure 336454DEST_PATH_IMAGE053
(26)
Figure 571126DEST_PATH_IMAGE054
(27)
Figure 726164DEST_PATH_IMAGE055
(28)
Figure 729892DEST_PATH_IMAGE056
the i well section porosity change rate amplitude parameter at the end of t time is dimensionless;
Figure 125232DEST_PATH_IMAGE057
the i well section permeability change rate amplitude parameter at the end of the t time is dimensionless;
Figure 581621DEST_PATH_IMAGE058
the cohesive strength change rate amplitude parameter of the i well section at the end of the t time is dimensionless;
and (3) calculating the permeability change, and according to the conversion of the porosity change ratio, calculating the formula as shown in formula (29):
Figure 540350DEST_PATH_IMAGE059
(29)
in the formula, k（i,t1）The near-well stratum permeability at the end of the time at the i well section, mD; k is a radical of（i,t0）For the initial near-well permeability at the time of Δ t for the i-well section, mD, in the first iteration, k（i,t0）K equal to that calculated in step S3（i）；
Calculating the change of cohesive strength as shown in formula (30):
Figure 195322DEST_PATH_IMAGE060
(30)
in the formula, S0（i，t1）The cohesive strength of the near-well stratum at the end of the time of i well section is MPa; s0（i，t0）At the beginning of the i well sectionWell formation cohesive strength, MPa, in the first iteration, S0（i，t0）Is equal to S calculated in step S40（i）；
S7: recalculating pressure distribution of each grid section of a well bore of the production section according to an inflow profile at the initial time (t = 0), and subtracting the pressure of the well bore by using formation static pressure to obtain reservoir inflow production differential pressure of each grid section; calculating the inflow intensity of oil, gas and water of a new grid section according to the porosity and permeability at the time t to form a new inflow profile;
calculating the pressure distribution of the shaft by adopting the inflow intensity of the shaft of each shaft section at the initial moment (t = 0), wherein the calculation formula of the actual bottom hole flow pressure of each point of the horizontal section is shown as the formula (31):
Figure 355039DEST_PATH_IMAGE061
(31)
in the formula, Pwf（i，t1）The actual bottom hole flowing pressure of the ith well section at the end of delta t is MPa; pwf（i-1，t1）The actual bottom hole flow pressure of the i-1 th well section at the end of delta t is Mpa; delta Pk（i，t1）The flow pressure loss of the ith well section in unit length at the end of delta t is MPa/m; delta Pk（i，t1）The flow rate is calculated by adopting a flow friction pressure drop formula according to the inflow rate at the initial time (t = 0), and the actual wellbore flow rate of the ith wellbore section is the sum of the inflow rates of all grids from the wellbore section to the toe end;
the calculation formula of the actual production pressure difference of each well section of the horizontal section is shown as the formula (32):
Figure 49457DEST_PATH_IMAGE062
(32)
in the formula,. DELTA.P（i，t1）The actual production pressure difference of the ith well section at the end of delta t is MPa;
the fluid output speed calculation formula at the time of Δ t is shown as the formulas (33), (34), (35) and (36):
Figure 343035DEST_PATH_IMAGE063
in the formula, Qo(i,t1)The oil inflow intensity at i well section at the end of time delta t, m3/（d·m）；Qw(i,t1)Water inflow intensity at i well section at end of time Δ t, m3/（d·m）；Qg(i,t1)The gas inflow intensity at i well section at the end of time Δ t, m3/（d·m）；Ql(i,t1)The fluid inflow intensity at i well section at the end of time at, m3/（d·m）；k(i,t1)The average value of each permeability at the i well section at the end of the delta t moment;
the total flow rate calculation is shown in equation (37):
Figure 55776DEST_PATH_IMAGE064
(37)
Vf(i,t1)the fluid inflow velocity at the i well section at the end of the time delta t is m/min; da is the diameter of a shaft at the well section i, and m;
s8: calculating the sand output, sand content and comprehensive inflow index of each new grid section according to the new inflow strength and cohesion strength at the time t, and obtaining a new non-uniform distribution profile of all inflow indexes at the time t:
calculating the average inflow velocity and cohesive strength of the whole well section to obtain the average inflow velocity V of the fluid at the end of the time delta tfa(t1)And average cohesive strength S0a(t1)，Vfa(t1)And S0a(t1)V of all well sections respectivelyf(i,t1)And S0(i,t1)The arithmetic mean of (a);
the sand production index calculation formula is shown as the formula (38):
Figure 42187DEST_PATH_IMAGE065
(38)
in the formula, Jxs(t1)At time t, the sand indexqsThe sand production strength is L/(d.m); u shapefFluid viscosity, mpa.s;
calculating the sand production rate and the sand concentration according to the inflow conditions, as shown in the formula (39):
Figure 676430DEST_PATH_IMAGE066
(39)
Qs(i,t1)the sand production rate at the i well section at the time t is L/(d.m);
the sand content calculation formula is shown as the formula (40):
Figure 524432DEST_PATH_IMAGE067
(40)
Cs(i,t1)the sand concentration at the end i well section at the time t is dimensionless;
the integrated inflow coefficient calculation formula is shown as equation (41):
Figure 357258DEST_PATH_IMAGE068
(41)
in the formula, Z(i,t1)The comprehensive inflow coefficient at the i well section at the end of the delta t time is dimensionless; qsa(t1)Average sand production rate of whole well section at delta t time, L/(d.m), Q for whole well sections(i,t1)Taking an average value;
s9: calculating local inflow coefficients
The calculation formula is shown in equations (42) and (43):
Figure 717833DEST_PATH_IMAGE069
in the formula, PIFsThe local inflow coefficient of the sand production strength is dimensionless; PIFlThe local inflow coefficient is the liquid production intensity, and is dimensionless; qsmax(t1)The highest sand production rate of the whole well section at the end of time delta t, L/(d.m), Vfmax(t1)The maximum fluid inflow velocity of the whole well section at the end of the time delta t, m/min, and Q at each point of the whole wells(i,t1)And Vf(i,t1)Taking the highest value;
s10: the production time is increased by Δ t, the iterative calculation of the next time step Δ t is continued from S6, the dynamic evolution of the sand liquid output profile is circularly realized, and various inflow profile predictions at any time t are realized.
2. The heterogeneous reservoir horizontal well sand fluid production profile dynamic evolution simulation and prediction method as claimed in claim 1, wherein Δ H is in a range of 0.2-0.5 m.
3. The heterogeneous reservoir horizontal well sand fluid production profile dynamic evolution simulation and prediction method of claim 1,
Figure 636110DEST_PATH_IMAGE070
respectively taking 2.65, 1 and 2.42.
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