CN113882842A - Method for detecting development scale of early steam cavity along horizontal well - Google Patents

Method for detecting development scale of early steam cavity along horizontal well Download PDF

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CN113882842A
CN113882842A CN202010617437.5A CN202010617437A CN113882842A CN 113882842 A CN113882842 A CN 113882842A CN 202010617437 A CN202010617437 A CN 202010617437A CN 113882842 A CN113882842 A CN 113882842A
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steam
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CN113882842B (en
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张胜飞
李秀峦
苟燕
金瑞凤
王红庄
张忠义
孙新革
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Petrochina Co Ltd
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
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Abstract

The invention discloses a method for detecting the development scale of an early steam cavity along a horizontal well, which comprises the following steps: obtaining rock fragment composition and well logging data of a horizontal steam injection well; calculating the heat conductivity coefficient of the horizontal steam injection well at the steam injection temperature and the specific heat capacity of the horizontal steam injection well at the steam injection temperature, and further calculating the heat diffusion coefficients of different sections of the horizontal steam injection well; steam injection is started to carry out circulating preheating on the horizontal well group; stopping steam injection, and performing a cooling test on the horizontal steam injection well; and analyzing the cooling test data, and analyzing the scale of a steam cavity formed above the horizontal steam injection well by combining the thermal diffusion coefficient and the steam injection duration. The invention can obtain the thermophysical property parameters and the development scale of the steam cavity of different horizontal sections by utilizing the existing well drilling and logging data and combining simple well closing operation, thereby assisting in judging the local steam absorption and liquid production capacity and assisting in compiling the regulation and control optimization scheme. The method has the advantages of low operation technical requirement, cost saving, high reliability, no strict operation limitation and the like.

Description

Method for detecting development scale of early steam cavity along horizontal well
Technical Field
The invention relates to the field of oilfield development, in particular to a method for detecting the development scale of an early steam cavity along a horizontal well.
Background
The reserves of thick oil are huge worldwide, and the mainstream technology for developing the thick oil at present is steam huff and puff, steam flooding, SAGD and improved methods thereof. A large amount of heat is brought into an oil reservoir through steam, crude oil is heated, and the viscosity of the crude oil is greatly reduced. SAGD (steam assisted gravity drainage) is to deploy double horizontal wells at the bottom of an oil reservoir, continuously inject steam from an upper horizontal well, and continuously produce oil from a lower horizontal well. The steam is continuously expanded upwards under the action of the super-heavy oil, the steam is condensed when encountering a cold oil reservoir to release latent heat, condensed water and heated crude oil flow to a lower production well under the action of gravity, and under the lifting actions of underground pumping, gas lift and the like, an oil-water mixture reaches the ground and is subjected to emulsion breaking and oil-water separation, so that the super-heavy oil is obtained. SAGD gives full play to the advantages of strong reservoir control capability and high oil production speed of the horizontal well, combines the advantage of high recovery efficiency of the gravity drainage technology, is the main technology for developing the ultra-thick oil at present, and is widely applied to the development of the ultra-thick oil and the oil sand at home and abroad. The method is influenced by factors such as strong reservoir heterogeneity, weak well track control capacity, improper starting strategy, unreasonable injection and production point design and the like, has the problems of difficulty in Subcool regulation and control, low horizontal section exploitation degree, uneven underground temperature, low oil drainage speed and the like of about 1/3 produced SAGD double-horizontal well groups, overcomes the adverse effects of factors such as reservoir heterogeneity, well track deviation, unsatisfactory starting strategy, unreasonable injection and production point deployment and the like, and has remarkable economic value for improving the exploitation degree of the long horizontal wells.
Theories and practices prove that the underground pressure distribution can be adjusted by putting tail pipes and FCDs or optimizing injection-production operation strategies, the liquid production profile is improved, and the purpose of promoting the horizontal well to be uniformly used is achieved. In order to apply the optimization measures, the development scale of the early steam cavity along the horizontal well must be known, and a targeted optimization scheme is formulated well by well according to the development of the steam cavity or the steam suction condition of a reservoir. Therefore, the method is particularly important for detecting the development scale of the early steam cavity along the horizontal well. The current conventional methods are as follows:
1) and (5) carrying out four-dimensional seismic testing and analyzing the scale of the steam cavity. The method is generally used for steam cavity detection developed to a considerable scale, has the defects of high cost and strict limitation on well site ground operation, and is less adopted;
2) the numerical fitting method inputs geological model parameters through oil reservoir and shaft simulation software to predict the development of a steam cavity. Different models and parameter settings obtain different results, the reliability is low, and the method is generally used as an auxiliary means;
3) the resistive method, also accounts for the edges of the vapor chamber. The method is influenced by the development process of the upper horizon and is not suitable for complex geological structure conditions;
4) and (4) an observation well data analysis method is relatively credible. But only the situation of the corresponding horizontal segment can be read out due to the number and the positions of the observation wells.
Aiming at the defects of the existing method, the invention provides a method for detecting the development scale of an early steam cavity along a horizontal well by utilizing the unsteady heat transfer principle, and the development scale and the distribution of the steam cavity after the circulation preheating is finished can be analyzed. The method can be used for optimizing underground pressure distribution, improving the liquid production profile and achieving the purpose of promoting the horizontal well to be uniformly used.
Disclosure of Invention
The invention aims to provide a method for detecting the development scale of an early steam cavity along a horizontal well, which can analyze the development scale and the development distribution of the steam cavity after the circulation preheating is finished, and is used for optimizing the underground pressure distribution, improving the liquid production profile and promoting the uniform use of the horizontal well.
In order to achieve the purpose, the invention adopts the following technical scheme:
the invention provides a method for detecting the development scale of an early steam cavity along a horizontal well, which comprises the following steps:
s100, obtaining rock fragment composition and logging data of a horizontal steam injection well;
s200, calculating the heat conductivity coefficient of the horizontal steam injection well at the steam injection temperature according to the logging data; calculating the specific heat capacity of the horizontal steam injection well at the steam injection temperature according to the rock debris composition, and further calculating the thermal diffusion coefficients of different sections of the horizontal steam injection well by combining logging data;
s300, starting steam injection of the horizontal well group for cyclic preheating;
s400, stopping steam injection, and performing a cooling test on the horizontal steam injection well;
and S500, analyzing the cooling test data, and analyzing the scale of a steam cavity formed above the horizontal steam injection well by combining the thermal diffusion coefficient and the steam injection duration.
In the art, conventional well log data includes, for example, neutrons, natural gammas, resistivities, natural potentials, and the like, as well as interpreted porosity, permeability, water saturation, shale content, and the like.
And in the cooling test process, the heat is naturally transmitted to the deep part of the stratum, and the temperature near the well is reduced.
According to the detection method of the present invention, preferably, the cooling test data includes temperature-time data during the cooling test;
the process of analyzing the cooling test data comprises the following steps:
using log (. DELTA.t) as abscissa, T*Taking a relation graph for the ordinate, fitting a straight line passing through the origin, and obtaining a slope K;
wherein, the delta t is the time of the cooling test and day;
T*obtained by the formula (13):
Figure BDA0002564216550000031
in the formula:
t is the temperature measured in the cooling test process, DEG C;
Tsthe temperature of the circulating steam injection is DEG C;
Tithe initial reservoir temperature, deg.C.
According to the detection method of the present invention, preferably, the analyzing the scale of the steam cavity formed above the horizontal steam injection well comprises:
the steam chamber height is calculated by equation (17):
Figure BDA0002564216550000032
in the formula:
r is the steam cavity height (i.e. steam cavity heating radius), m;
λ＝8.64×104(1-day 86400 s);
α is the thermal diffusion coefficient, m2/s；
Delta t is the time of the cooling test, day;
tjdays for steam injection.
According to the detection method of the present invention, preferably, the thermal diffusivity is calculated by equation (20):
α＝λ/ρCp (20)
in the formula:
lambda is the heat conductivity coefficient of the horizontal steam injection well at the steam injection temperature, W/(m DEG C);
rho is density, Kg/m3；
CpThe specific heat capacity of the horizontal steam injection well at the steam injection temperature is J/(g.K).
According to the detection method of the invention, preferably, the thermal conductivity λ of the horizontal steam injection well at the steam injection temperature is calculated by the formula (23):
Figure BDA0002564216550000041
in the formula:
λhthe heat conductivity coefficient of a certain horizontal section of the horizontal steam injection well is W/(m DEG C);
phi is the porosity;
S1for the total liquid phase saturation, take S1＝1；
T is temperature, DEG C.
According to the detection method of the invention, preferably, the specific heat capacity C of the horizontal steam injection well at the steam injection temperaturepCalculated by equation (24):
Cp＝fcsCp,css+ffsCp,fs+fbCp,b+fwComw (24)
in the formula:
fcsthe mass fraction of the coarse sand is;
ffsthe mass fraction of the fine sand is;
fbis the mass fraction of the crude oil;
fwis the water mass fraction;
Cp,bthe specific heat capacity of the crude oil is J/(g.K);
Cp,csthe specific heat capacity of the coarse sand is J/(g.K);
Cp,fsthe specific heat capacity of the fine sand is J/(g.K);
Cp,wthe specific heat capacity of water is J/(g.K);
t is temperature, DEG C, 50-300 ℃.
According to the detection method of the invention, preferably, the rock fragment composition is obtained by well logging analysis, including the coarse sand mass fraction fcsFine sand mass fraction ffsAnd crude oil mass fraction fb；
Mass fraction of water fwCalculated by the following formula:
Figure BDA0002564216550000042
in the formula:
Kbis the compression factor of the oil, Pa;
Kwis the compressibility factor of water, Pa;
ρbis the density of oil, Kg/m3；
ρwIs the density of water, Kg/m3；
Delta P is the difference between steam injection pressure and atmospheric pressure, Pa;
and Soi is the initial oil saturation.
According to the detection method of the present invention, preferably, the specific heat capacity of each component is calculated according to the following relationship:
Cp,cs＝0.738+1.518×10-3T-2.026×10-6T2；
Cp,fs＝0.778+1.400×10-3T-0.964×10-6T2；
Cp,b＝1.557+5.219×10-3T-8.686×10-6T2；
Cp,w＝4.19J/(g·K)。
according to the detection method of the present invention, preferably, S400 specifically includes: stopping steam injection, and closing the well; continuously recording temperature-time data in the horizontal steam injection well;
the time delta t of the temperature reduction test is the well-closing time, generally 10-100 days, and the well-closing time can be stopped as long as enough high-quality data points can be obtained. Because the longer the well choke time, the more energy is lost, the more unfavorable the subsequent SAGD start-up process is.
According to the detection method of the present invention, preferably, the cyclic preheating time in S300 is greater than or equal to 3 months.
The technical principle of the invention relates to the following aspects:
one-dimensional single heat source unsteady state heat transfer
FIG. 1 shows the unsteady heat transfer process of a one-dimensional single heat source. Wherein the inner diameter of the shaft is rwThe well length is L, the heat conduction rate is Q, the reservoir density is rho, and the specific heat capacity is CpThe thermal conductivity coefficient is K, and the porosity is phi; and assuming heat conductionThe coefficient and specific heat capacity are influenced by temperature negligibly, and the reservoir density and porosity are kept unchanged.
Taking a unit with length of 1, radius of r + delta r, cross-section area of A2 pi r, heat flux of q, initial temperature of Ti。
Steady state solution
According to the Fourier law, when the initial temperature is TiEffective radius r, heated to TsThe heating rates were:
Figure BDA0002564216550000051
transient solution of constant heating rate
Although the heat transfer in oil reservoirs has long been studied, the specific heat transfer pattern of horizontal wells or steam chambers within the reservoir has not received attention. Mathematically, such problems can be described by a one-dimensional radial heat flux equation:
Figure BDA0002564216550000061
wherein:
α is the thermal diffusion coefficient, m2/s；
T is temperature, DEG C;
r is the distance, m;
t is time, s.
Assuming no heat loss between the two where heat conduction occurs, the solution can be expressed by exponential product decomposition or line source decomposition as follows:
Figure BDA0002564216550000062
wherein,
Tiinitial temperature, deg.C;
q is the heat flux per unit length, W/m;
k is the thermal conductivity coefficient, W/m DEG C;
γ＝r2/(4λα)；
λ＝8.64×104(1day＝86400s)；
in the formula EiIs an exponential function, which is defined as follows:
Figure BDA0002564216550000063
wherein,
u is a virtual variable;
Figure BDA0002564216550000064
the exponential function can be transformed through a series of transformations into a simpler form:
Figure BDA0002564216550000065
in this equation, the size of n depends on the order of x and the required resolution precision. When x <0.01, equation (5) can be simplified to:
Ei(-x)＝ln(1.781x) (6)
will EiSubstituting formula (3) to obtain:
Figure BDA0002564216550000066
wherein s represents the thermal epidermal effect.
When γ/t <0.01 and the thermal skin effect is neglected (s ═ 0), the above equation becomes:
Figure BDA0002564216550000071
here, the number of the first and second electrodes,
Figure BDA0002564216550000072
the thermal pulse test of an object is carried out by using the formula (8) in which the thermal conductivity is calculated by using the formula (8 b).
Transient solution under constant temperature conditions
During a conventional steam injection or circulation phase, if the wellbore is already saturated with steam, the well pressure and temperature should be certain. In this case, the heat flux is not constant, but continuously decreases. This transient variation process under constant pressure has been described by a number of scholars. Also, after a period of steam injection at a constant steady temperature, it is possible to obtain:
Figure BDA0002564216550000073
wherein,
Figure BDA0002564216550000074
however, the problem of equation (9) is that it is difficult to accurately measure the heat flow q of each part inside the horizontal well bore during steam injection. In fact, this is exactly what is needed to evaluate the efficiency of heat transfer and to determine the effectiveness of early steam chamber development, and therefore a one-dimensional unsteady solution is not satisfactory.
Temperature decay test
Temperature decay tests are widely used for reservoir flow characteristic estimation in hydrocarbon reservoirs, and can be used in field heating processes to determine heating characteristics along a horizontal wellbore.
In the SAGD operation, after circulating steam injection for a long time, a temperature reduction test is generally performed. A temperature recorder (thermocouple or fiber optic sensor) is placed in the wellbore and the temperature is recorded along the horizontal wellbore. When the steam injection is stopped and the temperature is reduced, the temperature along the shaft is quickly reduced in an early stageAnd a tendency of slow decline in the latter stage. The rate of temperature decrease will vary with the position of the temperature recorder. When the temperature of the circulating steam injection is TsInitial reservoir temperature of TiAnd when the temperature in the shaft is T during well closing, obtaining the formulas (10) and (11) according to the formulas (3) and (9):
Figure BDA0002564216550000075
Figure BDA0002564216550000076
wherein,
qjthe heat flow before well closing is W/m;
k is the thermal conductivity coefficient, W/m DEG C;
delta t is the well closing time, day;
tjdays for steam injection;
γrw＝r2/(4λα)
qjcannot be measured accurately, but decreases with time. Combining formulae (10) and (11), eliminating qj. Dimensionless temperature T*Is defined as:
Figure BDA0002564216550000081
wherein,
Figure BDA0002564216550000082
in the formula (13), the temperature T of the shaft is measured by the test, Ts，TiIs a known condition. Thus, T can be found experimentally*. In the formula (13), log (. DELTA.t) is plotted as abscissa, T*Drawing a relation graph for the ordinate to obtain a straight line passing through the origin, and fitting to obtain a slope K:
Figure BDA0002564216550000083
when the development time is sufficiently long, tj>>The delta t can be ignored, and the gamma can be calculated according to the K valuerw：
Figure BDA0002564216550000084
Thus, α can be expressed as:
Figure BDA0002564216550000086
the heating radius r of the steam cavity is as follows:
Figure BDA0002564216550000085
application conditions
Through mathematical derivation, the invention can obtain the relationship between the temperature at a certain point of the double heat sources and the time and distance, but the derivation of the equation needs certain preconditions:
1) ignoring physical property changes in the vertical direction near the wellbore, including thermal diffusivity alpha, oil saturation Soi, porosity, density and the like;
2) the heat transfer mode in the formation is only heat conduction, and does not consider heat convection;
3) the steam injection condition is stable, namely the temperature, the pressure and the flow are constant;
4) the well closing test time is far shorter than the steam injection time;
5) the porosity of the reservoir is unchanged in the testing process of steam injection and closed well;
6) the liquid phase saturation is the residual oil saturation.
The beneficial effects of the invention include:
the invention can obtain the thermophysical property parameters and the development scale of the steam cavity of different horizontal sections by utilizing the existing well drilling and logging data and combining simple well closing operation, thereby assisting in judging the local steam absorption and liquid production capacity and assisting in compiling a regulation and control optimization scheme. The method has the advantages of low operation technical requirement, cost saving, high reliability, no strict operation limitation and the like.
The present invention provides a specific application process, which may include the following steps, but is not limited thereto, and each step may be omitted or adjusted according to the existing conditions in the actual application process.
1) Drilling a horizontal production well above (e.g., about 1m above) the reservoir bottom boundary;
2) then, drilling a horizontal steam injection well above the vertical (for example, about 5m above the vertical) of the horizontal production well by using a conventional magnetic guiding technology, recording rock debris while drilling, and analyzing to obtain the rock debris composition;
3) after drilling, putting a logging tool in, and obtaining information such as porosity, oil saturation, density and the like near the horizontal steam injection well;
4) according to the porosity and the gas injection temperature explained by logging, calculating the heat conductivity coefficient lambda of the reservoir rock near the horizontal gas injection well at the gas injection temperature; analyzing the composition Zi of rock debris recorded from different sections of the horizontal steam injection well, and calculating the specific heat capacity C at the steam injection temperatureP(ii) a Combining density data obtained by well logging, calculating thermal diffusion coefficients alpha of different sections of the horizontal steam injection well;
5) then, a pipe column structure is put in, an optical fiber is put in the horizontal steam injection well for continuous temperature measurement, a continuous oil pipe is put in the horizontal production well, and a distributed thermocouple is arranged in the horizontal production well;
6) the horizontal well group starts steam circulation, the steam injection temperature, pressure and flow are constant, and the circulation preheating lasts for enough time, generally more than 3 months;
7) stopping steam injection, and closing the well; continuously recording temperature-time data by an optical fiber in the horizontal steam injection well;
8) ending the well closing, and analyzing the temperature drop data of the phase; using log (. DELTA.t) as abscissa, T*Drawing a relation graph for the ordinate to obtain a straight line passing through the origin, and fitting to obtain a slope K; recombination of thermal diffusion coefficient alpha and steam injection time tjAccording to
Figure BDA0002564216550000091
The scale of the steam cavity formed above the horizontal steam injection well is analyzed.
According to the invention, through the application of interpretation while drilling, well logging interpretation and empirical relationship, the oil reservoir thermophysical property parameters of the horizontal steam injection well are obtained; and (3) putting a continuous temperature measuring device into the horizontal steam injection well, closing the well after the circulation preheating is finished, and recording the relation of the temperature in the well closing stage along with the time by the continuous temperature measuring device. And fitting the recorded data, and substituting the data into the derived unsteady heat transfer model to calculate the radius of the steam cavity developing along the horizontal well.
Drawings
FIG. 1 is a schematic diagram of one-dimensional single-heat-source unsteady heat transfer.
FIG. 2 is a graph of downhole temperature T recorded by fiber in a steam injection well over time T during a cyclic preheat-stuffer well in an example embodiment.
Figure 3 is a graph of the process of fitting T x-log 10(T) data during one cycle of preheat-blind well in an example.
FIG. 4 is a graph of the thermal diffusion coefficient along a horizontal well in the examples.
FIG. 5 is a steam chamber elevation view along a horizontal well in an example.
Detailed Description
In order to more clearly illustrate the invention, the invention is further described below in connection with preferred embodiments. It is to be understood by persons skilled in the art that the following detailed description is intended to be illustrative and not restrictive, and is not intended to limit the scope of the invention.
All numerical designations of the invention (e.g., temperature, time, concentration, weight, and the like, including ranges for each) may generally be approximations that vary (+) or (-) in increments of 0.1 or 1.0 as appropriate. All numerical designations should be understood as preceded by the term "about".
This example performed early steam cavity development scale measurements along the horizontal well for the following reservoirs.
1. Reservoir geology and SAGD operating conditions
The geology and operating parameters of the target reservoir are shown in table 1:
table 1 example reservoir geology and operational parameters table
Figure BDA0002564216550000101
Figure BDA0002564216550000111
2. Determination of reservoir thermophysical parameters along horizontal well
Through well logging analysis, rock fragment composition and saturated oil-water data are obtained, and the fragment composition of a certain horizontal section of the horizontal steam injection well is shown in the following table 2:
TABLE 2 composition of rock fragments in a horizontal section of a horizontal steam injection well
Components Mass fraction
Oil 0.1044
Coarse sand 0.3145
Fine sand 0.5531
And combining the empirical relationship to obtain the thermal physical property parameters lambda, Cp, rho and alpha (T) of the oil layer at different positions. The determination of the thermophysical parameters is developed in connection with the following example, which is an analysis of the composition of the cuttings obtained from a well.
1) Density of heavy oil reservoir along horizontal well
Including oil density, water density, coarse sand density, fine sand density, and average density of saturated oil-water rock samples. By sampling and analyzing, the density of oil, water, coarse sand and fine sand can be measured. The density of oil sands saturated with heavy oil was obtained by well log interpretation, and table 3 below is the density of oil sands for a certain horizontal section of a horizontal steam injection well.
TABLE 3 oil sand density of a certain horizontal section of a horizontal steam injection well
Temperature of Oil sand density of saturated thickened oil (g/mL)
20 2.2403
2) Porosity phi along horizontal well heavy oil reservoir
The porosity of a certain horizontal section of the horizontal steam injection well is 30.5 percent obtained by well logging interpretation.
3) Thermal conductivity lambda along a horizontal well heavy oil reservoir
The change of the thermal conductivity of the heavy oil reservoir along with the temperature is calculated by applying the following relational expression:
Figure BDA0002564216550000121
λhcoefficient of thermal conductivity (W/(m. degree. C))
Phi, porosity
S1Total liquid phase saturation
T, temperature (. degree. C.)
The oil reservoir does not contain gas, so S is taken11. Total liquid phase saturation S1And substituting the porosity phi and the steam injection temperature T into the relational expression to obtain the heat conductivity coefficient lambda. Table 4 below shows the data of the thermal conductivity at different temperatures for a certain horizontal section of the horizontal steam injection well.
TABLE 4 Heat conductivity coefficient of horizontal steam injection well at different temperatures in a certain horizontal section
Temperature of Thermal conductivity lambda (W/(m. degree. C.))
20 4.0034
50 3.7946
100 3.5059
150 3.2716
200 3.0767
225 2.9908
250 2.9113
4) Specific heat capacity of heavy oil reservoir along horizontal well
Calculating the specific heat capacity of the heavy oil reservoir by applying the following relational expression,
Cp＝fcsCp,css+ffsCp,fs+fbCp,b+fwComw (24)
wherein,
fcsmass fraction of coarse sand
ffsMass fraction of fine sand
fbMass fraction of crude oil
fwMass fraction of water
Cp,bCrude oil specific heat capacity J/(g.K)
Cp,csSpecific heat capacity of coarse sand J/(g.K)
Cp,fsSpecific heat capacity of fine sand J/(g.K)
Cp,wSpecific heat capacity of water J/(g.K)
T, temperature, DEG C (50-300 ℃ C.)
The specific heat capacity of each component is calculated according to the following empirical relationship:
Cp,cs＝0.738+1.518×10-3T-2.026×10-6T2
Cp,fs＝0.778+1.400×10-3T-0.964×10-6T2
Cp,b＝1.557+5.219×10-3T-8.686×10-6T2
Cp,w＝4.19J/(g·k)
recording rock debris in the process of drilling a horizontal well, obtaining rock debris composition samples with mixed average in each horizontal section, obtaining the mass fraction of coarse sand, fine sand and crude oil after analysis, and calculating the mass fraction of water by combining with the initial oil saturation Soi of logging interpretation
Figure BDA0002564216550000131
KbIs the compression factor of the oil, Pa;
Kwis the compressibility factor of water, Pa;
ρbis the density of oil, Kg/m3；
ρwIs the density of water, Kg/m3；
Δ P is the difference between the gas injection pressure and the atmospheric pressure, Pa.
5) Thermal diffusivity along horizontal well heavy oil reservoir
α＝λ/ρCp (20)
In summary, the thermal physical property parameters λ, Cp, α of the oil reservoir at different levels can be obtained by logging data and combining the above relational expressions. The following table 5 shows the calculation results of the thermal diffusivity α (T) with temperature on a certain horizontal section of the horizontal steam injection well.
TABLE 5 thermal diffusivity alpha at different temperatures for a certain horizontal section of a horizontal steam injection well
Temperature of Coefficient of thermal diffusion (10)-6m2/s)
20 1.8282
50 1.7951
100 1.7472
150 1.7132
200 1.6924
225 1.6861
250 1.6825
Table 6 below is the calculated thermal diffusivity for a horizontal well at different intervals.
TABLE 6 thermal diffusivity of a horizontal well at different intervals
Well location (m) Ts(℃) Coefficient of thermal diffusion alpha (10)-6m2/s)
20 221 1.6868
50 221 1.6522
100 221 1.6868
150 221 1.6534
200 221 1.6534
250 221 1.6875
300 221 1.6865
350 221 1.6869
390 221 1.6766
3. Detection of scale of development along horizontal well steam cavity
Closing the well after stopping steam injection, continuously monitoring the change of the downhole temperature T recorded by the optical fiber in the steam injection well along with the time T, and FIG. 2 is the temperature-time relation recorded in a cyclic preheating-well closing process.
The initial temperature Ti of the oil reservoir, the steam injection temperature Ts and the downhole temperature T in the well-closing stage are known
Figure BDA0002564216550000141
The parameter T can be calculated*Data T star-log recorded at each point10(t) the slope K of the different temperature measurement points was plotted (see FIG. 3), and the fitting results are shown in Table 7 below:
TABLE 7T × log10(t) results of graph fitting
Figure RE-GDA0002666239480000151
Because the well closing time delta t and the steam injection days t are knownjγ can be calculated from the following relationshiprw，
Figure BDA0002564216550000152
The thermal diffusion coefficient alpha combining the pointsiR, the development scale of the steam chamber, was calculated according to the following formula, and the results are shown in table 8.
Figure BDA0002564216550000153
TABLE 8 steam Chamber development Scale for well test interpretation after Cyclic Pre-heating
Figure BDA0002564216550000154
From the results of the above calculations, α i (fig. 4) and steam chamber height r (fig. 5) along the horizontal well can be plotted.
The invention can obtain the thermophysical property parameters and the development scale of the steam cavity of different horizontal sections by utilizing the existing well drilling and logging data and combining simple well closing operation, thereby assisting in judging the local steam absorption and liquid production capacity and assisting in compiling regulation and optimization schemes. The method has the advantages of low operation technical requirement, cost saving, high reliability, no strict operation limitation and the like.
It should be understood that the above-mentioned embodiments of the present invention are only examples for clearly illustrating the present invention, and are not intended to limit the embodiments of the present invention, and it will be obvious to those skilled in the art that other variations or modifications may be made on the basis of the above description, and all embodiments may not be exhaustive, and all obvious variations or modifications may be included within the scope of the present invention.

Claims (10)

1. A method for detecting the development scale of an early steam cavity along a horizontal well comprises the following steps:
s100, obtaining rock fragment composition and logging data of a horizontal steam injection well;
s200, calculating the heat conductivity coefficient of the horizontal steam injection well at the steam injection temperature according to the logging data; calculating the specific heat capacity of the horizontal steam injection well at the steam injection temperature according to the rock debris composition, and further calculating the thermal diffusion coefficients of different sections of the horizontal steam injection well by combining logging data;
s300, starting steam injection of the horizontal well group for cyclic preheating;
s400, stopping steam injection, and performing a cooling test on the horizontal steam injection well;
and S500, analyzing the cooling test data, and analyzing the scale of a steam cavity formed above the horizontal steam injection well by combining the thermal diffusion coefficient and the steam injection duration.
2. The method for detecting the development scale of the early steam cavity along the horizontal well according to claim 1, wherein the cooling test data comprises temperature-time data in the cooling test process;
the process of analyzing the cooling test data comprises the following steps:
using log (. DELTA.t) as abscissa, T*Taking a relation graph for the ordinate, fitting a straight line passing through the origin, and obtaining a slope K;
wherein, the delta t is the time of the cooling test and day;
T*obtained by the formula (13):
Figure FDA0002564216540000011
in the formula:
t is the temperature measured in the cooling test process, DEG C;
Tsthe temperature of the circulating steam injection is DEG C;
Tithe initial reservoir temperature, deg.C.
3. The method for detecting the development scale of the early steam cavity along the horizontal well according to claim 2, wherein the analyzing the scale of the steam cavity formed above the horizontal steam injection well comprises:
the steam chamber height is calculated by equation (17):
Figure FDA0002564216540000012
in the formula:
r is the steam cavity height, m;
λ＝8.64×104；
α is the thermal diffusion coefficient, m2/s；
Delta t is the time of the cooling test, day;
tjdays for steam injection.
4. The early steam cavity development scale detection method along the horizontal well according to claim 3, wherein the thermal diffusivity is calculated by an equation (20):
α＝λ/ρCp (20)
in the formula:
lambda is the heat conductivity coefficient of the horizontal steam injection well at the steam injection temperature, W/(m DEG C);
rho is density, Kg/m3；
CpThe specific heat capacity of the horizontal steam injection well at the steam injection temperature is J/(g.K).
5. The method for detecting the development scale of the early steam cavity along the horizontal well according to claim 4, wherein the thermal conductivity coefficient lambda of the horizontal steam injection well at the steam injection temperature is calculated by the formula (23):
Figure FDA0002564216540000021
in the formula:
λhthe heat conductivity coefficient of a certain horizontal section of the horizontal steam injection well is W/(m DEG C);
phi is the porosity;
S1for the total liquid phase saturation, take S1＝1；
T is temperature, DEG C.
6. The method for detecting development scale of early steam cavity along horizontal well according to claim 5, wherein specific heat capacity C of horizontal steam injection well at steam injection temperaturepCalculated by equation (24):
Cp＝fcsCp,css+ffsCp,fs+fbCp,b+fwComw (24)
in the formula:
fcsthe mass fraction of the coarse sand is;
ffsthe mass fraction of the fine sand is;
fbis the mass fraction of the crude oil;
fwis the water mass fraction;
Cp,bthe specific heat capacity of the crude oil is J/(g.K);
Cp,csthe specific heat capacity of the coarse sand is J/(g.K);
Cp,fsthe specific heat capacity of the fine sand is J/(g.K);
Cp,wthe specific heat capacity of water is J/(g.K);
t is temperature, DEG C, 50-300 ℃.
7. The method for detecting the development scale of the early steam cavity along the horizontal well according to claim 6, wherein the rock debris composition obtained by well logging analysis comprises the gross sand mass fraction fcsFine sand mass fraction ffsAnd crude oil mass fraction fb；
Mass fraction of water fwCalculated by the following formula:
Figure FDA0002564216540000031
in the formula:
Kbis the compression factor of the oil, Pa;
Kwis the compressibility factor of water, Pa;
ρbis the density of oil, Kg/m3；
ρwIs the density of water, Kg/m3；
Delta P is the difference between steam injection pressure and atmospheric pressure, Pa;
and Soi is the initial oil saturation.
8. The method for detecting the development scale of the early steam cavity along the horizontal well according to claim 7, wherein the specific heat capacity of each component is calculated according to the following relation:
Cp,cs＝0.738+1.518×10-3T-2.026×10-6T2；
Cp,fs＝0.778+1.400×10-3T-0.964×10-6T2；
Cp,b＝1.557+5.219×10-3T-8.686×10-6T2；
Cp,w＝4.19J/(g·K)。
9. the method for detecting the development scale of the early steam cavity along the horizontal well according to claim 2, wherein S400 specifically comprises: stopping steam injection, and closing the well; continuously recording temperature-time data in the horizontal steam injection well;
and the time delta t of the temperature reduction test is the well-closing time.
10. The method for detecting the development scale of the early steam cavity along the horizontal well according to claim 9, wherein the cyclic preheating time in the S300 is more than or equal to 3 months.
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