Method for predicting early formation fluid properties after high-temperature high-pressure deep well perforation

Abstract

The present application relates to the technical field of well testing analysis, and is a high-temperature and high-pressure deep well perforation early formation fluid property prediction method. The method is performed according to the following steps: establishing a fitting equation of the maximum value of the average density of the downhole mixture of the early production test of the high-temperature and high-pressure deep well of the tested oil in the research area and the static pressure gradient at the perforation section after the normal production test of the high-temperature and high-pressure deep well of the tested oil; establishing a corresponding relationship table of the static pressure gradient T at the perforation section of the high-temperature and high-pressure deep well and the formation fluid property; and obtaining the predicted formation fluid property of the to-be-evaluated oil well from the maximum value of the average density of the downhole mixture of the early production test of the to-be-evaluated oil well. The present application provides a high-temperature and high-pressure deep well perforation early formation fluid property prediction method, fills the blank of the high-temperature and high-pressure deep well perforation early fluid property prediction technology, and has the characteristics of simplicity, high efficiency, low cost, and high accuracy.

Description

Technical Field

[0001] The present invention relates to the technical field of well testing analysis and is a method for predicting early-stage formation fluid properties after perforation in a high-temperature and high-pressure deep well. Background Art

[0002] Domestic oil resource exploration and development has entered the deep well stage from shallow wells. The wells faced are characterized by high temperature, high pressure, and deep wells. At present, many difficulties in shallow and medium-layer oil test exploration and production technology have been overcome, but there are still many problems that need to be solved in high-temperature and high-pressure deep well oil test technology. In order to reduce the safety risks of oil test, before perforating oil test, detailed design of oil test plan, tubing optimization and mechanical analysis, sand production prediction and production pressure difference control are required. During the design optimization process, formation fluid parameters need to be utilized. These fluid parameters are usually predicted based on recording and measurement data. However, due to the complex geological conditions in deep layers, recording and measurement and other technical means cannot fully and accurately predict the fluid properties of the formation, which often leads to large deviations in oil test plan and high oil test risks.

[0003] After perforating a high-temperature, high-pressure deep well, formation fluid enters the tubing string, causing wellhead pressure to rise. This necessitates determining fluid properties to support subsequent production pressure differential control, sand production prevention, and casing extrusion protection. The earlier and more accurate the fluid identification, the more beneficial it is for subsequent production. Currently, a method for predicting fluid properties early after perforating a high-temperature, high-pressure deep well is urgently needed. This method can help determine formation fluid properties as early as possible and optimize well testing plans as quickly as possible. Summary of the Invention

[0004] The present invention provides a method for predicting early-stage formation fluid properties after high-temperature and high-pressure deep well perforation, which overcomes the shortcomings of the above-mentioned existing technologies and can effectively solve the problem of the blank of existing technology for predicting early-stage fluid properties after high-temperature and high-pressure deep well perforation.

[0005] The technical solution of the present invention is achieved by the following measures: A method for predicting the properties of early-stage formation fluids after perforation in a high-temperature, high-pressure deep well is performed according to the following steps:

[0006] The first step is to collect the relevant parameters of early blowout after test perforation of oil wells in the study area;

[0007] The second step is to establish the maximum value of the average density of the downhole mixture in the early stage of high temperature and high pressure deep well oil testing. Computational models;

[0008] The third step is to calculate the maximum average density of the downhole mixture in the early stage of the high-temperature and high-pressure deep wells tested in the study area. The static pressure gradient T at the perforation section of a high-temperature, high-pressure deep well that has been tested is established. and the fitting equation of T;

[0009] The fourth step is to classify the properties of the actual produced formation fluids based on the static pressure gradient T at the perforation section of the high-temperature, high-pressure deep wells after normal production test, and to establish a corresponding relationship table between the static pressure gradient T at the perforation section of the high-temperature, high-pressure deep wells in the study area and the properties of the formation fluids.

[0010] The fifth step is to use the maximum value of the average density of the downhole mixture in the early stage of the oil test of the oil well to be evaluated The estimated value of the static pressure gradient at the perforation section after normal production of the oil well to be evaluated is calculated. By comparing the correspondence table between the static pressure gradient T at the perforation section and the formation fluid properties in the study area, the estimated formation fluid properties of the oil well to be evaluated are obtained.

[0011] The following are further optimizations and / or improvements to the above technical solutions:

[0012] In the first step above, the parameters related to early blowout after perforation for oil wells in the study area include: the highest wellhead shut-in pressure P when shutting in after perforation; 井口 、The volume of the tubing string in the well per meter V 内容 , the density of the killing fluid in the whole wellbore during perforation ρ 压井液 , the volume of killing fluid produced when the well is opened and blowout is V, the wellhead pressure P' when the volume of killing fluid produced at the wellhead is V 井口 , vertical depth h in the middle of the oil layer.

[0013] In the second step above, the maximum value of the average density of the downhole mixture in the early stage of high-temperature and high-pressure deep well oil testing is ρ 平均max Calculated according to the following formula 1:

[0014]

[0015]

[0016] Where V 内容 is the volume per meter of the tubing string in the well, V is the volume of the killing fluid produced when the well is opened and blowout occurs, and P 井口 is the highest shut-in pressure at the wellhead after perforation, P′ 井口 is the wellhead pressure when the wellhead produces the killing fluid volume V, ρ 压井液 is the density of the wellbore killing fluid during perforation.

[0017] In the third step above, The fitting equation of and T is:

[0018] T=kρ 平均max -a Formula 3

[0019] Where k and a are coefficients.

[0020] In the fourth step above, when establishing the correspondence table between the static pressure gradient T and the formation fluid properties at the perforation section of the high-temperature and high-pressure deep wells in the study area, the formation fluid properties were divided into five categories, namely, formation water, oil-water mixture, crude oil, natural gas + water or natural gas + oil mixture, and natural gas. The values ​​of the static pressure gradient T at the perforation section corresponding to the five types of formation fluid properties decrease in sequence.

[0021] The present invention provides a method for predicting the properties of early-stage formation fluids after perforating in high-temperature and high-pressure deep wells, which fills the technical gap of predicting the properties of early-stage fluids after perforating in high-temperature and high-pressure deep wells and has the characteristics of simplicity, efficiency, low cost and high accuracy. BRIEF DESCRIPTION OF THE DRAWINGS

[0022] Attachment Figure 1 The oil well tested in Example 6 of the present invention Correlation analysis diagram of T. DETAILED DESCRIPTION

[0023] The present invention is not limited to the following embodiments, and specific implementation methods can be determined based on the technical solutions of the present invention and actual conditions.

[0024] The present invention will be further described below in conjunction with the embodiments:

[0025] Example 1: The method for predicting early-stage formation fluid properties after perforation in a high-temperature, high-pressure deep well is performed according to the following steps:

[0026] The first step is to collect the relevant parameters of early blowout after test perforation of oil wells in the study area;

[0027] The second step is to establish the maximum value of the average density of the downhole mixture in the early stage of high temperature and high pressure deep well oil testing. Computational models;

[0028] The third step is to calculate the maximum average density of the downhole mixture in the early stage of the high-temperature and high-pressure deep wells tested in the study area. The static pressure gradient T at the perforation section of a high-temperature, high-pressure deep well that has been tested is established. and the fitting equation of T;

[0029] The fourth step is to classify the properties of the actual produced formation fluids based on the static pressure gradient T at the perforation section of the high-temperature, high-pressure deep wells after normal production test, and to establish a corresponding relationship table between the static pressure gradient T at the perforation section of the high-temperature, high-pressure deep wells in the study area and the properties of the formation fluids.

[0030] The fifth step is to use the maximum value of the average density of the downhole mixture in the early stage of the oil test of the oil well to be evaluated The estimated value of the static pressure gradient at the perforation section after normal production of the oil well to be evaluated is calculated. By comparing the correspondence table between the static pressure gradient T at the perforation section and the formation fluid properties in the study area, the estimated formation fluid properties of the oil well to be evaluated are obtained.

[0031] Example 2: As an optimization of the above example, in the first step, the parameters related to early blowout after perforation of oil wells in the study area include: the highest wellhead shut-in pressure P when shutting in after perforation 井口 、The volume of the tubing string in the well per meter V 内容 , the density of the killing fluid in the whole wellbore during perforation ρ 压井液 , the volume of killing fluid produced when the well is opened and blowout is V, the wellhead pressure P' when the volume of killing fluid produced at the wellhead is V 井口 , vertical depth of the middle oil layer h;

[0032] Example 3: As an optimization of the above example, in the second step, the maximum value of the average density of the downhole mixture in the early stage of high temperature and high pressure deep well oil testing is Calculated according to the following formula 1:

[0033]

[0034]

[0035] Where V 内容 is the volume per meter of the tubing string in the well, V is the volume of the killing fluid produced when the well is opened and blowout occurs, and P 井口 is the highest shut-in pressure at the wellhead after perforation, P′ 井口 is the wellhead pressure when the wellhead produces the killing fluid volume V, ρ 压井液 is the density of the wellbore killing fluid during perforation.

[0036] The maximum average density of the downhole mixture during early blowout of high-temperature and high-pressure deep well oil testing The derivation process of the calculation model is as follows:

[0037] When the wellhead production volume is V, the height of the downhole killing fluid + formation production mixture (i.e. the downhole mixture after high temperature and high pressure deep well perforation) in the tubing is

[0038] P 地层压力 =ρ 压井液 gh+P 井口 ,

[0039] P 流压 =P′ 井口 +ρ 压井液 g(h-h1)+ρ 平均 gh1,

[0040] Formation output, production pressure difference ≥ 0, that is: ΔP=P地层压力 -P 流压 ≥0,

[0041] ρ 压井液 gh+P 井口 -[P′ 井口 +ρ 压井液 g(h-h1)+ρ 平均 gh1]≥0,

[0042] P 井口 -P′ 井口 +gh1(ρ 压井液 -ρ 平均 )≥0,

[0043]

[0044]

[0045] The maximum value of the average density of the underground mixture is

[0046] Example 4: As an optimization of the above example, in the third step, The fitting equation of and T is:

[0047] T=kρ 平均max -a Formula 3

[0048] Where k and a are coefficients.

[0049] Example 5: As an optimization of the above example, in the fourth step, when establishing a correspondence table between the static pressure gradient T and the formation fluid properties at the perforation section of the high-temperature and high-pressure deep well in the study area, the formation fluid properties are divided into five categories, namely, formation water, oil-water mixture, crude oil, natural gas + water or natural gas + oil mixture, and natural gas. The values ​​of the static pressure gradient T at the perforation section corresponding to the five types of formation fluid properties decrease in sequence.

[0050] Example 6: The method for predicting early-stage formation fluid properties after perforation in a high-temperature, high-pressure deep well was used to predict the formation fluid properties of Well GT1, a well to be predicted in the southern margin of the Junggar Basin in Xinjiang. The specific operations are as follows:

[0051] The static pressure gradient T of the perforated sections of 15 layers in the area, including LT1, TW1, and HT1, which have been tested, was collected (see Table 1). Based on the relevant data of the perforation and blowout of the above oil layers, the static pressure gradient T of the tested wells was calculated according to Formula 1. For tested oil wells Correlation analysis was performed with T (see Figure 1 ), the relationship expression between the two is:

[0052] Based on the static pressure gradient T at the perforation section of the tested oil well and the formation fluid properties of the tested oil layer in Table 1, a corresponding reference table between the two in the region is established, see Table 2.

[0053] The early data of the predicted well GT1 after perforation are as follows:

[0054] ① Known shut-in pressure after perforation, the highest shut-in pressure at the wellhead, P 井口 =58.89MPa;

[0055] ② Volume per meter of tubing in the well V 内容 =7L / m;

[0056] ③ Open the well and release the blowout, producing killing fluid V = 36.7m3;

[0057] ④ When the output volume V, the wellhead pressure P' 井口 =79.95MPa;

[0058] ⑤ During perforation, the density of the fluid under full wellbore pressure, ρ 压井液 =1.3g / cm3;

[0059] ⑥ Vertical depth of the middle oil layer h = 6771.5m.

[0060] According to formula 1, the maximum average density of the GT1 downhole mixture (i.e., the well killing fluid and the formation production fluid) is:

[0061] Further, by The estimated static pressure gradient at the perforated section of Well GT1 after normal production during the oil test was 0.719 MPa / 100 m. Referring to Table 2, the predicted formation fluid in Well GT1 was crude oil. Later oil tests confirmed an oil reservoir, indicating an accurate prediction.

[0062] In summary, the present invention fills the gap in the technology for predicting early fluid properties after perforating in high-temperature, high-pressure deep wells. In the early stages of oil testing, it can quickly and accurately identify the early fluid properties after perforating in high-temperature, high-pressure deep wells, providing accurate guidance for controlling production pressure differences, preventing sand production from the formation, and protecting the casing from extrusion deformation.

[0063] The above technical features constitute the embodiments of the present invention, which have strong adaptability and implementation effect. Non-essential technical features can be added or removed according to actual needs to meet the requirements of different situations.

[0064] Table 1

[0065]

[0066] Table 2

[0067]

[0068]

Claims

1. A method for predicting early formation fluid properties after perforation in high-temperature and high-pressure deep wells, characterized by Follow these steps: The first step is to collect relevant parameters of early blowout after oil test perforation in deep wells in the study area; The second step is to establish the maximum value of the average density of the downhole mixture in the early stage of high temperature and high pressure deep well oil testing. Computational models; The third step is to calculate the maximum average density of the downhole mixture in the early stage of the high-temperature and high-pressure deep wells tested in the study area. The static pressure gradient T at the perforation section of a high-temperature, high-pressure deep well that has been tested is established. and the fitting equation of T; The fourth step is to classify the properties of the actual produced formation fluids based on the static pressure gradient T at the perforation section of the high-temperature, high-pressure deep wells after normal production test, and to establish a corresponding relationship table between the static pressure gradient T at the perforation section of the high-temperature, high-pressure deep wells in the study area and the properties of the formation fluids. The fifth step is to use the maximum value of the average density of the downhole mixture in the early stage of the deep well test to be evaluated The estimated value of the static pressure gradient at the perforation section after normal production of the deep well to be evaluated is calculated. By comparing the correspondence table between the static pressure gradient T at the perforation section and the formation fluid properties in the study area, the estimated formation fluid properties of the deep well to be evaluated are obtained.

2. The method for predicting early formation fluid properties after perforation in a high-temperature, high-pressure deep well according to claim 1 is characterized in that In the first step, the parameters related to early blowout after perforation for deep wells in the study area include: the highest wellhead shut-in pressure when shutting in after perforation; , the volume of the tubing string per meter in the well , Density of killing fluid in the whole wellbore during perforation 2. The volume of killing fluid produced when opening the well and releasing the blowout , wellhead production killing fluid volume Wellhead pressure , vertical depth in the middle of the oil layer .

3. The method for predicting early formation fluid properties after high-temperature and high-pressure deep well perforation according to claim 1 or 2, characterized in that In the second step, the maximum average density of the downhole mixture in the early stage of high temperature and high pressure deep well oil testing Calculated according to the following formula 1: Where, is the volume per meter of the tubing string in the well, The volume of killing fluid produced when the well is opened and blowout occurs. The highest shut-in pressure at the wellhead after perforation. The volume of killing fluid produced at the wellhead The wellhead pressure at is the density of the wellbore killing fluid during perforation.

4. The method for predicting early formation fluid properties after perforation in a high-temperature, high-pressure deep well according to claim 1 or 2, characterized in that In the third step, The fitting equation of and T is: Where k and a are coefficients.

5. The method for predicting early formation fluid properties after perforation in a high-temperature, high-pressure deep well according to claim 3 is characterized in that In the third step, The fitting equation of and T is: Where k and a are coefficients.

6. The method for predicting early-stage formation fluid properties after perforation in a high-temperature, high-pressure deep well according to claim 5 is characterized in that In the fourth step, when establishing the correspondence table between the static pressure gradient T and the formation fluid properties in the perforation section of high-temperature and high-pressure deep wells in the study area, the formation fluid properties are divided into five categories, namely, formation water, oil-water mixture, crude oil, natural gas + water or natural gas + oil mixture, and natural gas. The values ​​of the static pressure gradient T in the perforation section corresponding to the five types of formation fluid properties decrease in sequence.

7. The method for predicting early-stage formation fluid properties after high-temperature and high-pressure deep well perforation according to claim 5 or 6, characterized in that In the fourth step, when establishing the correspondence table between the static pressure gradient T and the formation fluid properties in the perforation section of high-temperature and high-pressure deep wells in the study area, the formation fluid properties are divided into five categories, namely, formation water, oil-water mixture, crude oil, natural gas + water or natural gas + oil mixture, and natural gas. The values ​​of the static pressure gradient T in the perforation section corresponding to the five types of formation fluid properties decrease in sequence.

8. The method for predicting early-stage formation fluid properties after perforation in a high-temperature, high-pressure deep well according to claim 5 or 6, characterized in that In the fourth step, when establishing the correspondence table between the static pressure gradient T and the formation fluid properties in the perforation section of high-temperature and high-pressure deep wells in the study area, the formation fluid properties are divided into five categories, namely, formation water, oil-water mixture, crude oil, natural gas + water or natural gas + oil mixture, and natural gas. The values ​​of the static pressure gradient T in the perforation section corresponding to the five types of formation fluid properties decrease in sequence.

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