A method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics

Abstract

The present invention relates to the technical field of methods for obtaining formation pressure during oil drilling. The method is based on wellbore pressure differential and gas logging total hydrocarbon response characteristics. The method comprises collecting and organizing post-drilling logging data, well logging gas logging total hydrocarbon data, and drilling fluid density data from three or more reference wells drilled in the same block. The method then uses these data to calculate the reference well's formation pressure equivalent density and the bottomhole pressure differential equivalent density of mudstone sections at different burial depths. A bottomhole pressure differential-mud logging gas logging total hydrocarbon intersection trend chart is then plotted. Based on the trend chart, corresponding bottomhole pressure differential equivalent density ΔP coordinate data is read. Finally, the formation pressure equivalent density of the mudstone section in the target well is calculated. The method utilizes drilled reference wells and target wells currently being drilled in the same block as the processing objects. By combining a formation pressure calculation method based on well logging data with wellbore pressure differential and gas logging total hydrocarbon response characteristics, the method accurately obtains the formation pressure of the target well being drilled while drilling, achieving both timeliness and accuracy.

Description

Technical Field

[0001] The invention relates to the technical field of methods for obtaining formation pressure in oil drilling, and is a method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics. Background Art

[0002] In recent years, oil exploration has gradually expanded into deeper and more complex formations. While-drilling (LWD) formation pressure monitoring methods are no longer sufficient to meet the increasingly complex drilling landscape. Due to the lack of accurate LWD formation pressure monitoring, drilling accidents such as lost circulation, overflows, kicks, and blowouts frequently occur, resulting in significant economic losses and endangering the safety of construction workers. Currently, the main LWD formation pressure monitoring methods include the Sigma method, the DC index method, and logging-while-drilling (LWD) methods. Both the Sigma method and the DC index method involve numerous engineering parameters and are subject to significant human influence during the calculation process, resulting in poor LWD formation pressure monitoring accuracy. While LWD provides high formation pressure monitoring accuracy, its cost prohibits widespread adoption. Therefore, to accurately and rapidly obtain LWD formation pressure, developing an economical and accurate LWD formation pressure monitoring method is essential for exploration and development in deep and complex formations. Summary of the Invention

[0003] The present invention provides a method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics, which overcomes the shortcomings of the above-mentioned existing technologies and can effectively solve the problems of large human factor influence and poor accuracy in the calculation process of existing while-drilling formation pressure monitoring methods.

[0004] The technical solution of the present invention is achieved through the following measures: a method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics, comprising the following steps:

[0005] Step 1: Collect and organize post-drilling logging data, mud logging and gas logging data, and drilling fluid density data from three or more reference wells drilled in the same block. The logging data includes rock density and acoustic wave time difference of mudstone sections at different burial depths. In addition, real-time mud logging and gas logging data and drilling fluid density data are collected from the target wells being drilled.

[0006] Step 2: Based on the rock density data of one of the reference wells collected in step 1, calculate the overburden pressure of the reference well;

[0007] Based on the acoustic time difference data of mudstone sections at different burial depths of the reference well collected and sorted in step 1, a normal compaction trend line is established and the formation pressure equivalent density of the reference well is calculated;

[0008] Step 3: Calculate the equivalent density of the bottom hole pressure difference of the mudstone sections at different burial depths of the reference well based on the formation pressure of the mudstone sections at different burial depths of the reference well calculated in step 2 and the drilling fluid density used at the same well depth of the reference well;

[0009] Step 4: Repeat steps 2 and 3 to calculate the formation pressure equivalent density P of the mudstone sections at different burial depths in the remaining reference wells. P The equivalent density ΔP of the bottom hole pressure difference of mudstone sections with different burial depths;

[0010] Step 5: Intersect the total hydrocarbon logging data of three or more wells in the same formation mudstone section collected and organized in Step 1 with the bottom hole pressure difference equivalent density ΔP data of the same formation mudstone section calculated based on Step 4, establish a trend line based on the trend of sample landing points, and draw a bottom hole pressure difference-mud logging total hydrocarbon intersection trend graph;

[0011] Step 6: Substitute the total hydrocarbon logging data of the target well in the same formation mudstone section acquired in step 1 into the bottom hole pressure difference-logging gas logging total hydrocarbon intersection trend diagram established in step 5 to read the corresponding bottom hole pressure difference equivalent density ΔP coordinate data;

[0012] Step 7: Based on the corresponding bottom hole pressure difference equivalent density ΔP coordinate data read in step 6 and the drilling fluid density used in the mudstone section at the same well depth of the target well acquired in step 1, the formation pressure equivalent density of the mudstone section of the target well is calculated, and then the formation pressure data can be obtained based on the conversion relationship between the formation pressure equivalent density and the formation pressure.

[0013] The pressure equivalent density is equal to the pressure at a given depth divided by the product of the depth and the acceleration of gravity, that is, pressure equivalent density = pressure at a given depth / (depth x acceleration of gravity). The pressure equivalent density data can be converted to the corresponding pressure.

[0014] The following are further optimizations and / or improvements to the above technical solutions:

[0015] In step 2 above, the overburden pressure of the reference well is calculated using the following formula:

[0016]

[0017] Among them, G ob is the pressure gradient of the overburden at a certain depth, g / ml; ρ w 、h w is the water density and water depth, g / cm 3 ,m;ρ0,h o is the average density and thickness of the upper formation section without density logging, g / cm 3 ,m;ρ bi is the density scatter data at a certain depth, g / cm 3, Δh is the depth interval, m.

[0018] In step 2 above, the equivalent density of the reference well formation pressure is calculated using the following Eaton formula:

[0019]

[0020] Among them, P p is the formation pressure equivalent density, g / cm 3 ;P ob is the pressure equivalent density of the overburden, g / cm 3 ;P h is the equivalent density of formation hydrostatic pressure, g / cm 3 , Δt n is the time difference during normal formation compaction, us / m; Δt0 is the measured acoustic time difference of the formation, us / m; N is the Eaton index, a coefficient related to the formation.

[0021] In step 3 above, the following formula is used to calculate the equivalent density of the bottom hole pressure difference in the mudstone sections at different burial depths of the reference well:

[0022] ΔP=P p -ρ i

[0023] Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i Drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

[0024] In step 7 above, the formation pressure equivalent density of the mudstone section of the target well is calculated using the following formula:

[0025] P p =ΔP+ρ i

[0026] Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i is the drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

[0027] The present invention takes the drilled reference wells and the target wells being drilled in the same block as the processing objects, combines the formation pressure calculation method based on logging data and the wellbore pressure difference with the gas logging full hydrocarbon response characteristics, and accurately obtains the formation pressure of the target well being drilled while drilling, with the characteristics of timeliness and accuracy. BRIEF DESCRIPTION OF THE DRAWINGS

[0028] Attachment Figure 1 This is a flow chart of the method for obtaining formation pressure while drilling based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to the present invention;

[0029] Attachment Figure 2 This is the cross-trend diagram of bottom hole pressure difference and full hydrocarbon logging of a mudstone section in a reference well;

[0030] Attachment Figure 3 This is a diagram showing the bottom hole pressure difference reading for a mudstone section in the target well. DETAILED DESCRIPTION

[0031] 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.

[0032] The present invention improves the method for monitoring formation pressure while drilling, and is applicable to obtaining formation pressure while drilling from various gas logging full hydrocarbon display layers, forming a method for obtaining formation pressure while drilling based on wellbore pressure difference and gas logging full hydrocarbon response characteristics. This method is easy to obtain data, and does not affect the drilling construction progress while obtaining formation pressure. It has low cost and higher accuracy than the Sigma method and the DC index method. It is applicable to both water-based and oil-based drilling fluids, enriching the means of monitoring formation pressure while drilling. This technology, which is both economical and accurate, will have good application prospects.

[0033] The present invention will be further described below in conjunction with the embodiments:

[0034] Example

[0035] As attached Figure 1 As shown, the method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics includes the following steps:

[0036] Step 1: Collect and organize post-drilling logging data, mud logging and gas logging data, and drilling fluid density data from three or more reference wells drilled in the same block. The logging data includes rock density and acoustic wave time difference of mudstone sections at different burial depths. In addition, real-time mud logging and gas logging data and drilling fluid density data are collected from the target wells being drilled.

[0037] Step 2: Based on the rock density data of one of the reference wells collected in Step 1, calculate the overburden pressure of the reference well using the following formula:

[0038]

[0039] Among them, G ob is the pressure gradient of the overburden at a certain depth, g / ml; ρ w 、h w is the water density and water depth, g / cm 3 ,m;ρ0,h ois the average density and thickness of the upper formation section without density logging, g / cm 3 ,m;ρ bi is the density scatter data at a certain depth, g / cm 3 , Δh is the depth interval, m;

[0040] Based on the acoustic transit time data of mudstone sections at different burial depths of the reference well collected in step 1, a normal compaction trend line is established, and the formation pressure equivalent density of the reference well is calculated using the following Eaton formula:

[0041]

[0042] Among them, P p is the formation pressure equivalent density, g / cm 3 ;P ob is the pressure equivalent density of the overburden, g / cm 3 ;P h is the equivalent density of formation hydrostatic pressure, g / cm 3 , Δt n is the time difference during normal formation compaction, in μs / m; Δt0 is the measured acoustic time difference of the formation, in μs / m; N is the Eaton index, a coefficient related to the formation;

[0043] Step 3: Based on the formation pressures of the reference well at different burial depths calculated in step 2 and the drilling fluid density used at the same depth in the reference well, calculate the equivalent density of the bottom hole pressure difference of the reference well at different burial depths using the following formula:

[0044] ΔP=P p -ρ i

[0045] Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i Drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 ;

[0046] Step 4: Repeat steps 2 and 3 to calculate the formation pressure equivalent density P of the mudstone sections at different burial depths in the remaining reference wells. P The equivalent density ΔP of the bottom hole pressure difference of mudstone sections with different burial depths;

[0047] Step 5: Intersect the total hydrocarbon logging data of three or more wells in the same formation mudstone section collected and organized in Step 1 with the bottom hole pressure difference equivalent density ΔP data of the same formation mudstone section calculated based on Step 4, establish a trend line based on the trend of sample landing points, and draw a bottom hole pressure difference-mud logging total hydrocarbon intersection trend graph;

[0048] Step 6: Substitute the total hydrocarbon logging data of the target well in the same formation mudstone section acquired in step 1 into the bottom hole pressure difference-logging gas logging total hydrocarbon intersection trend diagram established in step 5 to read the corresponding bottom hole pressure difference equivalent density ΔP coordinate data;

[0049] Step 7: Based on the corresponding bottom hole pressure difference equivalent density ΔP coordinate data read in step 6 and the drilling fluid density used in the mudstone section at the same well depth of the target well acquired in step 1, the formation pressure equivalent density of the mudstone section of the target well is calculated, and then the formation pressure data can be obtained based on the conversion relationship between the formation pressure equivalent density and the formation pressure;

[0050] The formation pressure equivalent density of the mudstone section of the target well is calculated using the following formula:

[0051] P p =ΔP+ρ i

[0052] Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i is the drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

[0053] Implementation Cases

[0054] Taking Well Fu54 in the Fukang Sag of the Junggar Basin as an example, a method for obtaining formation pressure while drilling based on wellbore pressure difference and gas logging total hydrocarbon response characteristics includes the following steps:

[0055] Step 1: Collect and organize post-drilling logging data, mud logging and gas logging data, and drilling fluid density data from the four reference wells in the block, KT1, Fu48, Fu49, and Fu51. The logging data includes rock density and acoustic wave travel time for mudstone sections at different burial depths. In addition, real-time mud logging and gas logging data and drilling fluid density data for the target well, Fu54, which is currently being drilled, are collected (Table 1).

[0056] Step 2: Based on the rock density data of the four drilled reference wells KT1, Fu48, Fu49, and Fu51 collected in Step 1, calculate the overburden pressure of the reference wells using the following formula:

[0057]

[0058] Among them, G ob is the pressure gradient of the overburden at a certain depth, g / ml; ρ w 、h w is the water density and water depth, g / cm 3 ,m;ρ0,h ois the average density and thickness of the upper formation section without density logging, g / cm 3 ,m;ρ bi is the density scatter data at a certain depth, g / cm 3 , Δh is the depth interval, m.

[0059] Based on the acoustic time difference data of mudstone sections at different burial depths from four reference wells collected in step 1, a normal compaction trend line is established, and the equivalent density of the formation pressure in the reference wells is calculated using the following Eaton formula:

[0060]

[0061] Among them, P p is the formation pressure equivalent density, g / cm 3 ;P ob is the pressure equivalent density of the overburden, g / cm 3 ;P h is the equivalent density of formation hydrostatic pressure, g / cm 3 , Δt n is the time difference during normal formation compaction, us / m; Δt0 is the measured acoustic time difference of the formation, us / m; N is the Eaton index, a coefficient related to the formation, and the value of N in the Fukang Sag of the Junggar Basin is 1.5.

[0062] Step 3: Apply the formation pressure of a certain mudstone section in the four reference wells calculated in step 2 and the drilling fluid density at the same depth of the reference wells to calculate the equivalent density of the bottom hole pressure difference of a certain mudstone section in the reference wells using the following formula:

[0063] ΔP=P p -ρ i

[0064] Among them, P P is the formation pressure equivalent density, g / cm 3 ρ i is the drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

[0065] Step 4: The collected and collated logging gas logging total hydrocarbon data of a certain formation mudstone section of the four reference wells were intersected with the calculated bottom hole pressure difference equivalent density ΔP data of a certain formation mudstone section (Table 2). A trend line was established based on the trend of sample landing points. The correlation coefficient of the trend line was 0.968. A bottom hole pressure difference-logging gas logging total hydrocarbon intersection trend diagram was drawn ( Figure 2 ).

[0066] Step 5: Substitute the real-time acquired while-drilling gas logging total hydrocarbon data of a certain formation mudstone section of target well Fu54 into the reference well bottom hole pressure difference-mud logging gas logging total hydrocarbon intersection trend diagram to read the corresponding bottom hole pressure difference equivalent density ΔP coordinate data ( Figure 3 );

[0067] Step 6: Apply the bottomhole pressure difference of a certain mudstone section in the target well Fu54 and the density of the drilling fluid used at the same well depth in a certain mudstone section in the target well Fu54 to calculate the formation pressure equivalent density of a certain mudstone section in the target well Fu54 using the following formula:

[0068] P p =ΔP+ρ i

[0069] Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i is the drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

[0070] The total hydrocarbon value of the target well Fu54 in a mudstone section is 5066ppm. The bottom hole pressure difference and the total hydrocarbon value of the mudstone section in the target well Fu54 are read using the reference well bottom hole pressure difference and the mud logging gas logging cross trend chart. The bottom hole pressure difference equivalent density ΔP coordinate data is 0.11. The density of the drilling fluid used to collect the mudstone section is 1.66g / cm 3 , calculate the formation pressure equivalent density P of a mudstone section in the target well Fu54 p 1.55g / cm 3 After the target well Fu54 was drilled, the logging data was collected and the formation pressure calculation method in step 2 was applied to calculate the formation pressure equivalent density of a mudstone section in a formation of the target well Fu54 to be 1.52 g / cm 3 , the accuracy rate is 98.06%, and the conclusion is consistent with, meeting the needs of drilling construction.

[0071] 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.

[0072] Table 1. Real-time collection of total hydrocarbon and drilling fluid density data from logging while drilling

[0073]

[0074] Table 2 Drilling fluid density and total hydrocarbon collection of mudstone section in a formation of four reference wells

[0075]

Claims

1. A method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics, characterized in that The following steps are involved: Step 1: Collect and organize post-drilling logging data, mud logging and gas logging data, and drilling fluid density data from three or more reference wells drilled in the same block. The logging data includes rock density and acoustic wave time difference of mudstone sections at different burial depths. In addition, real-time mud logging and gas logging data and drilling fluid density data are collected from the target well being drilled. Step 2: Based on the rock density data of one of the reference wells collected in step 1, calculate the overburden pressure of the reference well; Based on the acoustic time difference data of mudstone sections at different burial depths of the reference well collected in step 1, a normal compaction trend line is established and the equivalent density of the formation pressure of the reference well is calculated; Step 3: Calculate the bottomhole pressure difference equivalent density of the mudstone sections at different burial depths of the reference well based on the formation pressure equivalent density of the mudstone sections at different burial depths calculated in step 2 and the drilling fluid density used at the same well depth of the reference well; Step 4: Repeat steps 2 and 3 to calculate the formation pressure equivalent density P of the mudstone sections at different burial depths in the remaining reference wells. P The equivalent density ΔP of the bottom hole pressure difference of mudstone sections with different burial depths; Step 5: Intersect the mud logging gas logging total hydrocarbon data of the same formation mudstone section from three or more drilled reference wells collected and sorted in Step 1 with the bottom hole pressure difference equivalent density ΔP data of the same formation mudstone section calculated based on Step 4, establish a trend line based on the sample landing point trend, and draw a bottom hole pressure difference-mud logging gas logging total hydrocarbon intersection trend graph; Step 6: Substitute the total hydrocarbon logging data of the target well in the same formation mudstone section acquired in step 1 into the bottom hole pressure difference-logging gas logging total hydrocarbon intersection trend diagram established in step 5 to read the corresponding bottom hole pressure difference equivalent density ΔP coordinate data; Step 7: Based on the corresponding bottom hole pressure difference equivalent density ΔP coordinate data read in step 6 and the drilling fluid density used in the mudstone section at the same well depth of the target well acquired in step 1, the formation pressure equivalent density of the mudstone section of the target well is calculated. Then, the formation pressure data of the target well can be obtained based on the conversion relationship between the formation pressure equivalent density and the formation pressure.

2. The method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to claim 1, characterized in that In step 2, the overburden pressure of the reference well is calculated using the following formula: Among them, G ob is the pressure gradient of the overburden at a certain depth, g / ml; ρ w 、h w is the water density and water depth, g / cm 3 ,m;ρ0,h o is the average density and thickness of the upper formation section without density logging, g / cm 3 ,m;ρ bi is the density scatter data at a certain depth, g / cm 3 , Δh is the depth interval, m.

3. The method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to claim 1 or 2, characterized in that In step 2, the reference well formation pressure equivalent density is calculated using the following Eaton formula: Among them, P p is the formation pressure equivalent density, g / cm 3 ;P ob is the pressure equivalent density of the overburden, g / cm 3 ;P h is the equivalent density of formation hydrostatic pressure, g / cm 3 , Δt n is the time difference during normal formation compaction, us / m; Δt0 is the measured acoustic time difference of the formation, us / m; N is the Eaton index, a coefficient related to the formation.

4. The method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to claim 1 or 2, characterized in that In step 3, the bottom hole pressure difference of the mudstone sections at different burial depths of the reference well is calculated using the following formula: ΔP=P p -r i Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i Drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

5. The method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to claim 3 is characterized in that In step 3, the bottom hole pressure difference equivalent density of mudstone sections at different burial depths of the reference well is calculated using the following formula: ΔP=P p -r i Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i Drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

6. The method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to claim 1 or 2, characterized in that In step 7, the formation pressure equivalent density of the mudstone section of the target well is calculated using the following formula: P p =ΔP+ρ i Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i is the drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

7. The method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to claim 3 is characterized in that In step 7, the formation pressure equivalent density of the mudstone section of the target well is calculated using the following formula: P p =ΔP+ρ i Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i is the drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

8. The method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to claim 4 is characterized in that In step 7, the formation pressure equivalent density of the mudstone section of the target well is calculated using the following formula: P p =ΔP+ρ i Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i is the drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

9. The method for obtaining formation pressure based on wellbore pressure difference and gas logging total hydrocarbon response characteristics according to claim 5, characterized in that In step 7, the formation pressure equivalent density of the mudstone section of the target well is calculated using the following formula: P p =ΔP+ρ i Among them, P p is the formation pressure equivalent density, g / cm 3 ρ i is the drilling fluid density, g / cm 3 ; ΔP is the bottom hole pressure difference equivalent density, g / cm 3 .

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