Method for testing pressure of carbonate rock formation fluid

Abstract

The invention discloses a carbonate rock formation fluid pressure testing method, and relates to the technical field of formation fluid pressure testing, and the method comprises the steps of S1, data acquisition and equipment installation, S2, test fluid injection, S3, pressure response detection, and S4, data analysis and calculation. According to the testing method, by collecting geological parameters and calculating the permeability anisotropy coefficient, a stratum model which is closer to reality can be constructed, specifically, in a carbonate rock stratum testing area, the permeability difference of different areas is determined based on geological analysis, a reliable basis is provided for subsequent testing, and the testing efficiency is improved. Meanwhile, the measured parameters such as the viscosity and density of the testing fluid and the stratum thickness are comprehensively considered for calculation, the obtained result is closer to the real stratum fluid pressure, accurate data support is provided, the testing precision and accuracy are improved, and decision errors caused by data errors are reduced.

Description

Technical Field

[0001] The present invention belongs to the technical field of formation fluid pressure testing, and particularly relates to a testing method for carbonate formation fluid pressure. Background Art

[0002] In oil and gas exploration and development, accurately measuring the carbonate formation fluid pressure is crucial for resource assessment, production plan design, and safe production. Traditional formation fluid pressure testing methods gradually expose many limitations when facing the complex characteristics of carbonate formations.

[0003] Previous testing methods lack comprehensiveness and depth in the geological data collection link, and do not fully consider the unique lithological combination, pore structure, and permeability anisotropy characteristics of carbonate rocks. This makes the constructed formation model deviate from the actual formation conditions, and it is difficult to accurately reflect the true seepage path and pressure distribution law of fluids in the formation, increasing the uncertainty and risk of production decisions. In view of the above problems, the following solutions are proposed. Summary of the Invention

[0004] The purpose of the present invention is to provide a testing method for carbonate formation fluid pressure. By collecting geological parameters and calculating the permeability anisotropy coefficient, a more practical formation model can be constructed, solving the problem that the prior art is difficult to accurately reflect the true seepage path and pressure distribution law of fluids in the formation.

[0005] To solve the above technical problems, the present invention is realized through the following technical solutions: The present invention is a testing method for carbonate formation fluid pressure, including: Step S1, data collection and equipment installation: Collect geological parameters, calculate the permeability anisotropy coefficient, and install pressure sensors and temperature sensors in both the injection well and the observation well; Step S2, injecting test fluid: Select modified brine and inject it into the formation through the injection well at a constant flow rate, while monitoring the injection pressure and temperature; Step S3, pressure response detection: Arrange observation wells around the injection well according to the formation conditions and install sensors to collect pressure and temperature data, and calculate the pressure propagation uniformity coefficient to judge the propagation uniformity; Step S4, data analysis and calculation: Calculate the pressure propagation speed from the time difference of the pressure changes in the injection well and the observation well, and calculate the formation fluid pressure in combination with each parameter value; The specific steps of the said step S4, data analysis and calculation include the following steps: Step S41: Compare the start of injection in the injection well with the moment of the first pressure change in the observation well to obtain the time difference , substitute it into the formula to calculate the pressure propagation speed , where is the distance between the starting point of the pressure wave propagation and the observation point; Step S42: Calculate the formation fluid pressure : ; where is the pressure of the observation well, is the viscosity of the test fluid, is the weighted average formation permeability, is the flow rate of the test fluid injected into the core, is the formation thickness, are respectively the distance between the injection well and the observation well and the radius of the injection well, is the density of the test fluid, are respectively the thermal expansion coefficients of the rock and the fluid, is the temperature difference between the observation well and the injection well, is the formation porosity; Preferably, the step S1, data acquisition and equipment installation specifically include the following steps: Step S11: Collect the data of geological exploration, core sample analysis and surrounding area research of the carbonate rock formation in the test area to obtain parameters; Step S12: Measure the horizontal permeability and the vertical permeability , and build a seepage model; Step S13: Calculate the permeability anisotropy coefficient ; Step S14: Install pressure sensors and temperature sensors in the test area; In the injection well, the pressure sensor can be installed near the bottom of the well or near the injection point, and the temperature sensor can be installed at one end of the injection pipeline close to the formation; In the observation well, the pressure sensor can be installed on the well wall at different depths, and the temperature sensor can be installed near the well wall and in a position with good heat conduction with the formation, and can be located at the position corresponding to the expected pressure change area in terms of depth.

[0006] Preferably, the formulas for calculating the permeability in the step S12 are respectively: When the core has high permeability, the permeability is calculated using the formula: ; where is the flow rate of the test fluid injected into the core, is the viscosity of the test fluid, is the core length, is the cross-sectional area of the core, is the pressure difference at both ends of the core at steady state; When the core has low permeability, the permeability is calculated using the formula: ; In the formula, is the volume of the pulsed fluid injected into the core, is the formation porosity, is the attenuation coefficient.

[0007] Preferably, step S2, injecting the test fluid specifically includes the following steps: Step S21: According to the geological information, select the modified brine and measure the dosage of the additive through the chemical compatibility index ; Step S22: Inject the test fluid into the formation through the injection well at a constant flow rate.

[0008] Preferably, in step S21, the chemical compatibility index has the following calculation formula: ; In the formula, is the total mass of the additive added to the test fluid, is the total mass of all components in the test fluid.

[0009] Preferably, step S3, pressure response detection specifically includes the following steps: Step S31: According to the formation permeability and the estimated pressure propagation range, arrange the observation wells and install pressure and temperature sensors in each observation well, and collect the pressure response and temperature data every second; Step S32: Use the pressure propagation uniformity coefficient to measure the pressure propagation uniformity; Step S33: Set the initial monitoring duration and observe the trend of the pressure response curve.

[0010] Preferably, in step S32, the pressure propagation uniformity coefficient has the following calculation formula: ; In the formula, is the total number of observation wells participating in the pressure monitoring, is the pressure response value monitored by the th observation well at a specific moment, is the arithmetic mean of the pressure response values of all observation wells at the same moment.

[0011] The present invention has the following beneficial effects: 1. The test method of the present invention collects geological parameters and calculates the anisotropy coefficient of permeability, thereby constructing a more realistic formation model. Specifically, in the carbonate formation test area, based on geological analysis, the permeability differences in different areas are determined to provide a reliable basis for subsequent tests. At the same time, the measured test fluid viscosity, density and formation thickness and other parameters are comprehensively considered for calculation. The obtained results are closer to the actual formation fluid pressure, provide accurate data support, improve the precision and accuracy of the test, and reduce decision-making errors caused by data errors.

[0012] 2. The present invention prepares modified brine based on geological information and controls the amount of additives through the chemical compatibility index, which can avoid adverse reactions between the test fluid and the native fluid of the formation, ensure that the original physical and chemical properties of the formation are not destroyed, and maintain the stability of the formation. At the same time, by arranging observation wells and evaluating the pressure propagation, it can more accurately monitor the changes in formation pressure, ensure the reliability of the test results, and reduce the risk of mining.

[0013] Of course, any product implementing the present invention does not necessarily need to achieve all of the advantages described above at the same time. BRIEF DESCRIPTION OF THE DRAWINGS

[0014] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings required for describing the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other accompanying drawings can be obtained based on these accompanying drawings without paying creative work.

[0015] Figure 1 The present invention is a flow chart of a method for testing fluid pressure in carbonate formations. DETAILED DESCRIPTION

[0016] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0017] See also Figure 1 As shown, the present invention is a method for testing the fluid pressure of a carbonate formation, comprising: Step S1, data collection and equipment installation: collect geological parameters, calculate the permeability anisotropy coefficient, and install pressure sensors and temperature sensors in both the injection well and the observation well; Step S2, Injecting Test Fluid: Select modified brine and inject it into the formation through the injection well at a constant flow rate while monitoring the injection pressure and temperature; Step S3, Pressure Response Detection: Arrange observation wells around the injection well according to the formation conditions and install sensors to collect pressure and temperature data, and calculate the pressure propagation uniformity coefficient to judge the propagation uniformity; Step S4, Data Analysis and Calculation: Calculate the pressure propagation velocity from the time difference of the pressure changes between the injection well and the observation wells, and calculate the formation fluid pressure in combination with various parameter values; Step S4, Data Analysis and Calculation specifically includes the following steps: Step S41: Compare the start of injection of the injection well with the moment of the first pressure change in the observation well to obtain the time difference , and substitute it into the formula to calculate the pressure propagation velocity , where is the distance between the starting point and the observation point of the pressure wave propagation; Step S42: Calculate the formation fluid pressure : ; where is the pressure of the observation well, is the viscosity of the test fluid, is the weighted average formation permeability, is the flow rate of the test fluid injected into the core, is the formation thickness, are the distances between the injection well and the observation well and the injection well radius respectively, is the density of the test fluid, are the thermal expansion coefficients of the rock and the fluid respectively, is the temperature difference between the observation well and the injection well, is the formation porosity; Step S1, Data Acquisition and Equipment Installation specifically includes the following steps: Step S11: Collect data on geological exploration, core sample analysis, and research on the surrounding area of the carbonate rock formation in the test area to obtain parameters; Step S12: Measure the horizontal permeability and the vertical permeability respectively, and build a seepage model; Step S13: Calculate the permeability anisotropy coefficient ; Step S14: Install pressure sensors and temperature sensors in the test area.

[0018] The formulas for calculating permeability in Step S12 are respectively: When the core has high permeability, the permeability is calculated using the formula: ; In the formula, is the flow rate of the test fluid injected into the core, is the viscosity of the test fluid, is the core length, is the cross-sectional area of the core, is the pressure difference across the core at steady state; When the core has low permeability, the permeability is calculated using the formula: ; In the formula, is the volume of the pulsed fluid injected into the core, is the formation porosity, is the attenuation coefficient.

[0019] Step S2: Injecting the test fluid specifically includes the following steps: Step S21: According to the geological information, select the modified brine and measure the dosage of the additive through the chemical compatibility index ; Step S22: Inject the test fluid into the formation through the injection well at a constant flow rate.

[0020] In step S21, the calculation formula of the chemical compatibility index is: ; In the formula, is the total mass of the additive added to the test fluid, is the total mass of all components in the test fluid.

[0021] Step S3: Pressure response detection specifically includes the following steps: Step S31: According to the formation permeability and the estimated pressure propagation range, arrange the observation wells and install pressure and temperature sensors in each observation well to collect pressure response and temperature data per second; Step S32: Use the pressure propagation uniformity coefficient to measure the pressure propagation uniformity; Step S33: Set the initial monitoring duration and observe the trend of the pressure response curve.

[0022] In step S32, the calculation formula of the pressure propagation uniformity coefficient is: ; In the formula, is the total number of observation wells participating in the pressure monitoring, is the The pressure response value monitored by a single observation well at a specific moment, is the arithmetic mean of the pressure response values of all observation wells at the same moment.

[0023] A specific application of this embodiment is as follows: Step S1, data collection and equipment installation: Step S11: Collect data such as geological exploration, core sample analysis, and research on the surrounding area of the target carbonate rock formation to obtain key parameters. Taking a certain area as an example, through the analysis of multiple coring wells, clarify the lithology ratio, such as 60% limestone and 40% dolomite; measure the porosity of 10 different cores using the helium injection method, with values ranging from 5% to 15% and an average of 10%; Step S12: Measure the horizontal permeability and vertical permeability using the steady-state and pulse decay methods, and build a seepage model based on this; When the core has high permeability, the permeability is calculated using the formula: ; In the formula, is the flow rate of the test fluid injected into the core, is the viscosity of the test fluid, is the core length, is the cross-sectional area of the core, is the pressure difference at both ends of the core at steady state; When the core has low permeability, the permeability is calculated using the formula: ; In the formula, is the volume of the pulse fluid injected into the core, is the formation porosity, is the attenuation coefficient; Step S13: Introduce the permeability anisotropy coefficient , whose value ranges from 2 to 10 in this area, and can assist in analyzing the characteristics of fluid flow; Step S14: Referring to the estimated depth of 3000 meters, temperature, and pressure of 50 MPa in the formation, select high-precision pressure and temperature sensors. The pressure sensor has an accuracy of ±0.01 MPa, a range of 75 MPa, and corrosion resistance, such as M5156-000005-250BG, HDA3840-A-400-124; the thermistor temperature sensor has an accuracy , fast response. The injection well is selected in the area where the formation fluid is active, such as near a fault; the observation wells are distributed 20-50 meters around the injection well according to the geological model. After installation, calibrate with a standard pressure and temperature source to ensure that the deviation is compliant; Step S2, inject the test fluid: Step S21: According to the preliminary geological information, select a modified brine that matches the chemical properties of the formation's native fluid and has good compatibility. For example, if the formation fluid in a certain area contains components such as sodium chloride and calcium chloride, then prepare a brine added with corrosion inhibitors and regulators. In a simulated formation environment, measure the fluid viscosity with a rotational viscometer , and the result is 2.5 mPa・s; use the pycnometer method combined with formation temperature and pressure correction to measure the density to be 1050 kg / m³. When determining the dosage of additives such as corrosion inhibitors and regulators, measure through the chemical compatibility index , and a value of 0.005 - 0.02 is more appropriate; Step S22: Inject the test fluid into the formation through the injection well at a constant flow rate of . This rate is estimated based on the formation permeability and porosity to avoid damaging the formation. During injection, use a high-precision flowmeter to limit the flow rate fluctuation within , such as or less. At the same time, collect the injection pressure and temperature data per second. For example, within a 100-second period, the injection pressure rises from 10 MPa to 12 MPa, and the temperature stabilizes at or so; Step S3. Pressure response detection: Step S31: At a specific distance from the injection well, according to the formation permeability and the estimated pressure propagation range, arrange observation wells at intervals of 10 - 50 meters. Install high-precision pressure and temperature sensors in each observation well, and collect the pressure response and temperature data per second. Taking the observation well 20 meters east as an example, when injecting for about 50 seconds, the pressure starts to rise from 15 MPa, and the temperature has fluctuations; Step S32: Use the pressure propagation uniformity coefficient to measure the pressure propagation uniformity. The formula for the pressure propagation uniformity coefficient is: ; In the formula, is the total number of observation wells participating in pressure monitoring, is the pressure response value monitored by the th observation well at a specific moment, is the arithmetic mean of the pressure response values of all observation wells at the same moment; Step S33: First set the initial monitoring duration , observe the trend of the pressure response curve. When the pressure change rate is continuously less than for 100 seconds, and the temperature change rate is less than When the pressure response is determined to be stable, end it in advance; otherwise, extend it by 500 seconds each time until the stable condition is met; Step S4, data analysis and calculation: Step S41: By comparing the start time of injection in the injection well with the time when the first obvious pressure change is detected in the observation well, accurate to 0.1 second, calculate the time difference , for example, for the observation well 20 meters eastward, the start time is 0 second, and the first change is 50 seconds, then , and then substitute it into the formula ( is the distance between the starting point and the observation point of the pressure wave propagation, here ), calculate the pressure propagation speed ; Step S42: Calculate the formation fluid pressure : ; In the formula, is the pressure of the observation well, is the viscosity of the test fluid, is the weighted average formation permeability, is the flow rate of the test fluid injected into the core, is the formation thickness, are respectively the distance between the injection well and the observation well and the radius of the injection well, is the density of the test fluid, are respectively the thermal expansion coefficients of the rock and the fluid, is the temperature difference between the observation well and the injection well, is the formation porosity.

[0024] In the description of this specification, the descriptions referring to terms such as "one embodiment", "example", "specific example", etc. mean that the specific features, structures, materials or characteristics described in connection with the embodiment or example are included in at least one embodiment or example of the present invention. In this specification, the schematic representations of the above terms do not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials or characteristics described can be combined in a suitable manner in any one or more embodiments or examples.

[0025] The above-disclosed preferred embodiments of the present invention are only used to help illustrate the present invention. The preferred embodiments do not describe all the details in detail, nor do they limit the invention to the specific embodiments described. Obviously, according to the content of this specification, many modifications and changes can be made. This specification selects and specifically describes these embodiments to better explain the principles and practical applications of the present invention, so that those skilled in the art can well understand and utilize the present invention. The present invention is only limited by the claims and their full scope and equivalents.

Claims

1. A method for testing fluid pressure in carbonate formations, characterized in that: The test method comprises the following steps: Step S1, data collection and equipment installation: collect geological parameters, calculate the permeability anisotropy coefficient, and install pressure sensors and temperature sensors in both the injection well and the observation well; Step S2, injecting a test fluid: selecting a modified brine, injecting it into the formation through an injection well at a constant flow rate, and monitoring the injection pressure and temperature at the same time; Step S3, pressure response detection: according to the formation conditions, observation wells are arranged around the injection well and sensors are installed to collect pressure and temperature data, and the pressure propagation uniformity coefficient is calculated to determine the propagation uniformity; Step S4, data analysis and calculation: calculate the pressure propagation velocity from the time difference between the injection well and the observation well pressure change, and calculate the formation fluid pressure in combination with various parameter values; The step S4, data analysis and calculation, specifically includes the following steps: Step S41: Compare the time when the injection well starts to be injected and the time when the first pressure change in the observation well occurs, and obtain the time difference , substitute into the formula Calculate the pressure propagation velocity , where is the distance between the starting point of pressure wave propagation and the observation point; Step S42: Calculate formation fluid pressure : ； In the formula, is the observation well pressure, To test the fluid viscosity, is the weighted average formation permeability, is the flow rate of the test fluid injected into the core, is the formation thickness, are the distance between the injection well and the observation well and the radius of the injection well, respectively. To test the fluid density, are the thermal expansion coefficients of rock and fluid, is the temperature difference between the observation well and the injection well, is the formation porosity.

2. A method for testing fluid pressure in carbonate formations according to claim 1, characterized in that: The step S1, data collection and equipment installation specifically includes the following steps: Step S11: Collect data on geological exploration of carbonate rock formations in the test area, core sample analysis, and surrounding area research to obtain parameters; Step S12: Measure the horizontal permeability respectively and vertical permeability , and build a seepage model; Step S13: Calculate the permeability anisotropy coefficient ; Step S14: Install a pressure sensor and a temperature sensor in the test area.

3. A method for testing the fluid pressure of a carbonate formation according to claim 2, characterized in that: The formulas for calculating the permeability in step S12 are: When the core has high permeability, the permeability is calculated using the formula: ; In the formula, is the flow rate of the test fluid injected into the core, To test the fluid viscosity, is the core length, is the cross-sectional area of ​​the core, The pressure difference between the two ends of the core at steady state; When the core has low permeability, the permeability is calculated using the formula: ； In the formula, is the volume of pulse fluid injected into the core, is the formation porosity, is the attenuation coefficient.

4. A method for testing the fluid pressure of a carbonate formation according to claim 1, characterized in that: The step S2, injecting the test fluid, specifically comprises the following steps: Step S21: Select modified brine based on geological information and use chemical compatibility index Measure the amount of additives used; Step S22: injecting a test fluid into the formation through the injection well at a constant flow rate.

5. A method for testing the fluid pressure of a carbonate formation according to claim 4, characterized in that: The chemical compatibility index in step S21 The calculation formula is: ； In the formula, is the total mass of additive added to the test fluid, is the total mass of all components in the test fluid.

6. A method for testing carbonate formation fluid pressure according to claim 1, characterized in that: The step S3, pressure response detection, specifically comprises the following steps: Step S31: Arrange observation wells according to the formation permeability and the estimated pressure propagation range, and install pressure sensors and temperature sensors in each observation well to collect pressure response and temperature data every second; Step S32: Propagate uniformity coefficient using pressure Measures the uniformity of pressure spread; Step S33: Set the initial monitoring time and observe the trend of the pressure response curve.

7. A method for testing carbonate formation fluid pressure according to claim 6, characterized in that: The pressure propagation uniformity coefficient in step S32 The calculation formula is: ； In the formula, is the total number of observation wells involved in pressure monitoring, For the The pressure response value monitored by an observation well at a specific time, It is the arithmetic mean of the pressure response values ​​of all observation wells at the same time.

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