Heavy oil reservoir nuclear magnetic resonance fluid identification method based on pore interval difference value

Abstract

The invention discloses a heavy oil reservoir nuclear magnetic resonance fluid identification method based on a pore interval difference value. The method comprises the following steps: fitting four T2 spectrums under the conditions of long and short waiting time and long and short echo intervals; respectively calculating the porosity component between each bin cell in the TA spectrum and the TB spectrum; calculating an oil content index and a corrected water content index; and overlapping the oil-containing index and the corrected water-containing index in the same direction under the same scale to form a fluid property identification effect picture, and evaluating the stratum by using the picture. The method has the advantages that the property condition of the deep fluid can be accurately reflected, and support is provided for oil and gas reservoir cognition; on the basis of logging response characteristics, by strengthening sensitive parameters, weakening inert parameters, establishing an oil-containing index and a corrected water-containing index and adopting a fluid property mode filling identification method, the formation fluid property is reflected, the method is simple, the effect is visual and clear, practicability is high, and operability is high.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas geological development, and particularly relates to a nuclear magnetic resonance fluid identification method for heavy oil reservoirs based on pore interval difference. Background Art

[0002] As a logging method that is not affected by the formation skeleton and can directly reflect the characteristics of formation fluids, nuclear magnetic resonance logging plays an important role in the identification of formation fluid properties. Its identification principle is based on the fact that in each measurement mode, the T2 spectrum morphology of reservoirs with different fluid properties is different under different waiting times and echo intervals, that is, the difference spectrum method and the shift spectrum method are used for qualitative identification. Among them, the difference spectrum method is aimed at light-medium viscosity oil and gas layers with crude oil viscosity less than 50 centipoise / 50°C. It uses the characteristics that the oil and gas activation time is longer than that of the water layer. When measuring with a short waiting time, only the water signal is restored, and when measuring with a long waiting time, the oil and gas signal can be restored. At this time, the T2 spectra measured at different waiting times are differenced to highlight the oil and gas signals, thereby identifying the formation fluid. The spectrum shift method is aimed at heavy oil reservoirs with crude oil viscosity greater than 50 centipoise / 50℃. It uses the echo interval to increase the forward shift of the nuclear magnetic resonance T2 spectrum. The forward shift rates of the T2 spectrum of different fluids are different. By designing a suitable echo interval, the oil and water signals can be separated, thereby identifying the formation fluid.

[0003] At present, MRIL-P logging instruments are often used in oilfield nuclear magnetic resonance logging. In long-term production experience, it is found that although the differential spectrum method can only be evaluated qualitatively, the image is intuitive and the analysis is clear, and good results have been achieved in the evaluation application process. Although the shift spectrum method has also achieved certain results in the application process, since the distribution range of heavy oil signals and capillary bound fluid signals is basically the same, in the deep reservoirs with complex pore structures in the oilfield, non-fluid information needs to be stripped off, and the image analysis of the forward rate is relatively abstract, which requires a high level of experience for the interpreter. In this case, a more direct and quantitative method for evaluating fluid properties is needed to guide subsequent development and construction plans. However, there is currently a lack of effective methods. Summary of the invention

[0004] In order to solve the above problems, the object of the present invention is to provide a method for identifying heavy oil reservoir nuclear magnetic resonance fluid based on pore interval difference.

[0005] In order to achieve the above object, the present invention provides a method for identifying heavy oil reservoir nuclear magnetic resonance fluid based on pore interval difference, which comprises the following steps performed in sequence:

[0006] 1) The original echo string data collected by the nuclear magnetic resonance logging system were processed using the nuclear magnetic resonance evaluation software to fit four T2 spectra under the conditions of long and short waiting time and long and short echo interval;

[0007] 2) The T2 spectrum in the long waiting time and short echo interval mode is defined as the TA spectrum, and the T2 spectrum in the long waiting time and long echo interval mode is defined as the TB spectrum, and then the porosity components of each bin in the TA spectrum and the TB spectrum are calculated respectively;

[0008] 3) Using the porosity components between the above bins, the oil index and the water index are calculated, and the water index is corrected to obtain a corrected water index;

[0009] 4) Overlap the oil content index and the corrected water content index in the same direction at the same scale to form a fluid property identification effect diagram, and use the diagram to evaluate the formation.

[0010] In step 1), the method of using nuclear magnetic resonance evaluation software to process the original echo string data collected by the nuclear magnetic logging system to fit four T2 spectra under the conditions of long and short waiting times and long and short echo intervals is: using nuclear magnetic resonance evaluation software including pretrosite, lead and ciflog to perform data detection, determine processing parameters, accumulate the echo strings, perform phase correction and multi-exponential fitting, and finally fit four high-quality T2 spectra under the conditions of long and short waiting times and long and short echo intervals.

[0011] In step 2), the formulas for respectively calculating the porosity components between each bin in the TA spectrum and the TB spectrum are as follows:

[0012]

[0013]

[0014] Among them, PnA represents the porosity component of the nth bin in the TA spectrum, and PnB represents the porosity component of the nth bin in the TB spectrum.

[0015] In step 3), the porosity component between the bins is used to calculate the oil index and the water index, and the water index is corrected to obtain the corrected water index as follows:

[0016] The oil content index F is obtained by the change of the porosity component between the 5th bins in the TA spectrum and the TB spectrum, which is used to quantitatively characterize the heavy oil signal. The formula is as follows:

[0017] F=P5A-P5B (3)

[0018] Among them, P5A is the porosity component of the 5th bin in the TA spectrum, and P5B is the porosity component of the 5th bin in the TB spectrum;

[0019] Similarly, the water content index M is obtained by using the change in the porosity component between the 7th bin in the TA spectrum and the TB spectrum, which is used to quantitatively characterize the water signal. The formula is as follows:

[0020] M=P7A-P7B (4)

[0021] Among them, P7A is the porosity component of the 7th bin in the TA spectrum, and P7B is the porosity component of the 7th bin in the TB spectrum;

[0022] The oil and gas correction coefficient N is calculated using the difference in porosity components between the 7th bin and the 8th bin in the TA spectrum. The water index M is then corrected using the oil and gas correction coefficient N to obtain the corrected water index g. The formula is as follows:

[0023]

[0024] g=N*M (6)

[0025] Among them, P8A is the porosity component of the 8th bin in the TA spectrum.

[0026] In step 4), the oil content index and the corrected water content index are overlapped in the same direction at the same scale to form a fluid property identification effect diagram, and the method of using the diagram to evaluate the formation is:

[0027] When the corrected water index g of a formation is much greater than 0 and the oil index F is near 0, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with a slash, indicating that the formation is mainly composed of water and is evaluated as a pure water layer; when the oil index F is much greater than 0 and the corrected water index g is near 0, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with a solid color, indicating that the formation is mainly composed of heavy oil and is evaluated as a pure oil layer; when the difference between the oil index F and the corrected water index g is small and they alternate in the formation, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with an alternating slash and solid color, indicating that the oil and water content in the formation is unstable and is evaluated as an oil and water layer.

[0028] The heavy oil reservoir nuclear magnetic resonance fluid identification method based on pore interval difference provided by the present invention has the following beneficial effects:

[0029] 1. The present invention relies on nuclear magnetic resonance logging to combine the pore change parameters of T2 spectrum intervals under different echo interval conditions to form a quantitative evaluation method, avoiding the problems of the original shift spectrum method's forward rate image analysis being abstract, requiring relatively high experience of the interpreters, and only being able to perform qualitative analysis. It can accurately reflect the properties of deep-layer fluids and provide support for the understanding of oil and gas reservoirs;

[0030] 2. Based on the logging response characteristics, the present invention strengthens sensitive parameters, weakens inert parameters, establishes an oil index and a corrected water index, and reflects the formation fluid properties by adopting a fluid property pattern filling and identification method. The method is simple, the effect is intuitive and clear, the practicability is strong, and the operability is high. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] Figure 1 This is a pore composition diagram of the nuclear magnetic resonance logging interval in the present invention.

[0032] Figure 2 This is a diagram showing the effect of fluid property recognition in an embodiment of the present invention. DETAILED DESCRIPTION

[0033] The present invention is described in detail below with reference to the accompanying drawings and specific embodiments.

[0034] The method for identifying heavy oil reservoir nuclear magnetic resonance fluid based on pore interval difference provided by the present invention comprises the following steps performed in sequence:

[0035] 1) The original echo string data collected by the nuclear magnetic resonance logging system were processed using nuclear magnetic resonance evaluation software, and four T2 spectra under the conditions of long and short waiting time and long and short echo interval were fitted.

[0036] T2 spectrum processing is the basis of nuclear magnetic resonance logging interpretation. The original echo string data collected by the MRIL-P nuclear magnetic logging system is a spin echo string signal in the time domain. To obtain high-quality T2 spectra from the spin echo string signal, data detection, determination of processing parameters, accumulation of echo strings, phase correction, and multi-exponential fitting are required, and finally four T2 spectra under the conditions of long and short waiting time and long and short echo intervals with high quality are fitted. The nuclear magnetic resonance evaluation software includes pretrosite, lead, and ciflog.

[0037] 2) The T2 spectrum in the long waiting time and short echo interval mode is defined as the TA spectrum, and the T2 spectrum in the long waiting time and long echo interval mode is defined as the TB spectrum, and then the porosity components of each bin in the TA spectrum and the TB spectrum are calculated respectively;

[0038] The envelope area of ​​the nuclear magnetic resonance T2 spectrum represents the total porosity of the reservoir, and the area within different T2 spectrum ranges represents the interval porosity of the reservoir. According to the morphology of the nuclear magnetic resonance T2 spectrum, the porosity components of each bin in the TA spectrum and TB spectrum are calculated using the following formulas (1) and (2): the ranges of each bin are 1-2ms, 2-4ms, 4-8ms, 8-16ms, ... 1024-2048ms, respectively, where the porosity components of each bin in the TA spectrum are: P1A, P2A, P3A...P13A; the porosity components of each bin in the TB spectrum are: P1B, P2B, P3B...P13B, respectively, as Figure 1 As shown:

[0039]

[0040]

[0041] 3) Using the porosity components between the above bins, the oil index and the water index are calculated, and the water index is corrected to obtain a corrected water index;

[0042] The T2 cutoff value of deep formations in oil fields is generally distributed around 33ms, and its heavy oil signal is located in the fifth bin interval, that is, in the range of 16-32ms. The movable free water level is after 32ms and is concentrated in the seventh bin interval, that is, in the range of 64-128ms. The echo interval is extended to move the nuclear magnetic resonance T2 spectrum forward, and the measured TB spectrum will be significantly earlier than the TA spectrum. In view of the above characteristics, when the fluid properties of the same reservoir are different, the sensitive interval of pore change is different. For oil layers, the sensitive interval of pore change will be mainly concentrated in the fifth bin interval, that is, in the range of 16-32ms. For water layers, the sensitive interval of pore change is mainly concentrated in the seventh bin interval, that is, in the range of 64-128ms. Accordingly, the oil content index F is obtained by changing the porosity component in the fifth bin interval in the TA spectrum and the TB spectrum, which is used to quantitatively characterize the heavy oil signal. The formula is as follows:

[0043] F=P5A-P5B (3)

[0044] Among them, P5A is the porosity component of the 5th bin in the TA spectrum, and P5B is the porosity component of the 5th bin in the TB spectrum;

[0045] Similarly, the water content index M is obtained by using the change in the porosity component between the 7th bin in the TA spectrum and the TB spectrum, which is used to quantitatively characterize the water signal. The formula is as follows:

[0046] M=P7A-P7B (4)

[0047] Among them, P7A is the porosity component of the 7th bin in the TA spectrum, and P7B is the porosity component of the 7th bin in the TB spectrum;

[0048] In production applications, it is found that although the water index M obtained above is theoretically feasible, the effect of using formula (4) to judge fluid properties is not ideal. Analysis of the reason shows that if the oil field has entered the middle and late stages of development, in the heavy oil reservoir, hydrocarbon substances with small molecular weight and low viscosity in crude oil will gradually dissolve in the formation water as the development level deepens. This part of the signal is mainly reflected in the 7th-8th bin interval, that is, in the range of 64-256ms in nuclear magnetic resonance logging, thus affecting the evaluation effect of the water index. In practice, the TA spectrum of the pure water layer is concentrated, and the peak position is distributed forward, that is, it also has the characteristics of the porosity component P7A>P8A in the interval. Based on this, the oil and gas correction coefficient N is calculated using the difference in porosity components between the 7th bin interval and the 8th bin interval, and then the oil and gas correction coefficient N is used to correct the water index M to obtain the corrected water index g. The formula is as follows:

[0049]

[0050] g=N*M (6)

[0051] Among them, P8A is the porosity component of the 8th bin in the TA spectrum.

[0052] 4) Overlap the oil content index and the corrected water content index in the same direction at the same scale to form a fluid property identification effect diagram, and use the diagram to evaluate the formation.

[0053] When the corrected water index g of a formation is much greater than 0 and the oil index F is near 0, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with a slash, indicating that the formation is mainly composed of water and is evaluated as a pure water layer; when the oil index F is much greater than 0 and the corrected water index g is near 0, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with a solid color, indicating that the formation is mainly composed of heavy oil and is evaluated as a pure oil layer; when the difference between the oil index F and the corrected water index g is small and they alternate in the formation, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with an alternating slash and solid color, indicating that the oil and water content in the formation is unstable and is evaluated as an oil and water layer.

[0054] The following is based on the nuclear magnetic resonance logging data of Well J in a certain oil field, combined with the accompanying drawings, to further describe the practical effect of the present invention:

[0055] Well J is a productivity evaluation well. The regional crude oil viscosity is 360 centipoise / 50°C, which belongs to a heavy oil reservoir. Figure 2 The following is the fluid property identification effect diagram of the oil well obtained by this method. Figure 2 It can be seen that for formations 40, 41, 42 and 54, the oil index F calculated based on the nuclear magnetic resonance T2 spectrum is basically 0, and the corrected water index g can reach about 2-2.5. The gap between the oil index F and the corrected water index g of these formations in the fluid property identification effect diagram is filled with oblique lines, indicating that these formations are mainly water and are evaluated as pure water layers. The oil index F of the 45-51 and 52-1 formations calculated according to the nuclear magnetic resonance T2 spectrum is basically above 2, and the corrected water index g is distributed in the range of 0-0.5. The gap between the oil index F and the corrected water index g of these formations in the fluid property identification effect diagram is filled with a solid color, indicating that these formations are mainly composed of heavy oil and are evaluated as pure oil layers; the corrected water index g of the 52 and 53 formations is about 1, and the oil index F is in the range of 0-0.5, with little difference. The gap between the oil index F and the corrected water index g of these formations in the fluid property identification effect diagram is filled with an alternating oblique line and a solid color, and is evaluated as the same layer of oil and water. The 45-51 formation of the well was tested for oil, and the submersible electric pump and 8mm oil nozzle were used for spraying. The daily oil production was 31.20 tons, the daily water production was 5.51 cubic meters, and the formation water content was 15%, which verified the reliability of the present invention in the identification of deep fluid properties in oil fields.

Claims

1. A method for identifying heavy oil reservoir nuclear magnetic resonance fluid based on pore interval difference, characterized in that: The identification method comprises the following steps performed in sequence: 1) The original echo string data collected by the nuclear magnetic resonance logging system were processed using the nuclear magnetic resonance evaluation software to fit four T2 spectra under the conditions of long and short waiting time and long and short echo interval; 2) The T2 spectrum in the long waiting time and short echo interval mode is defined as the TA spectrum, and the T2 spectrum in the long waiting time and long echo interval mode is defined as the TB spectrum, and then the porosity components of each bin in the TA spectrum and the TB spectrum are calculated respectively; 3) Using the porosity components between the above bins, the oil index and the water index are calculated, and the water index is corrected to obtain a corrected water index; 4) Overlap the oil content index and the corrected water content index in the same direction at the same scale to form a fluid property identification effect diagram, and use the diagram to evaluate the formation.

2. The method for identifying heavy oil reservoir nuclear magnetic resonance fluid based on pore interval difference according to claim 1, characterized in that: In step 1), the method of using nuclear magnetic resonance evaluation software to process the original echo string data collected by the nuclear magnetic logging system to fit four T2 spectra under the conditions of long and short waiting times and long and short echo intervals is: using nuclear magnetic resonance evaluation software including pretrosite, lead and ciflog to perform data detection, determine processing parameters, accumulate the echo strings, perform phase correction and multi-exponential fitting, and finally fit four high-quality T2 spectra under the conditions of long and short waiting times and long and short echo intervals.

3. The method for identifying heavy oil reservoir nuclear magnetic resonance fluid based on pore interval difference according to claim 1, characterized in that: In step 2), the formulas for respectively calculating the porosity components between each bin in the TA spectrum and the TB spectrum are as follows: Among them, PnA represents the porosity component of the nth bin in the TA spectrum, and PnB represents the porosity component of the nth bin in the TB spectrum.

4. The method for identifying heavy oil reservoir nuclear magnetic resonance fluid based on pore interval difference according to claim 1, characterized in that: In step 3), the porosity component between the bins is used to calculate the oil index and the water index, and the water index is corrected to obtain the corrected water index as follows: The oil content index F is obtained by the change of the porosity component between the 5th bins in the TA spectrum and the TB spectrum, which is used to quantitatively characterize the heavy oil signal. The formula is as follows: F=P5A-P5B (3) Among them, P5A is the porosity component of the 5th bin in the TA spectrum, and P5B is the porosity component of the 5th bin in the TB spectrum; Similarly, the water content index M is obtained by using the change in the porosity component between the 7th bin in the TA spectrum and the TB spectrum, which is used to quantitatively characterize the water signal. The formula is as follows: M=P7A-P7B (4) Among them, P7A is the porosity component of the 7th bin in the TA spectrum, and P7B is the porosity component of the 7th bin in the TB spectrum; The oil and gas correction coefficient N is calculated using the difference in porosity components between the 7th bin and the 8th bin in the TA spectrum. The water index M is then corrected using the oil and gas correction coefficient N to obtain the corrected water index g. The formula is as follows: g=N*M (6) Among them, P8A is the porosity component of the 8th bin in the TA spectrum.

5. The method for identifying heavy oil reservoir nuclear magnetic resonance fluid based on pore interval difference according to claim 1, characterized in that: In step 4), the oil content index and the corrected water content index are overlapped in the same direction at the same scale to form a fluid property identification effect diagram, and the method of using the diagram to evaluate the formation is: When the corrected water index g of a formation is much greater than 0 and the oil index F is near 0, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with a slash, indicating that the formation is mainly composed of water and is evaluated as a pure water layer; when the oil index F is much greater than 0 and the corrected water index g is near 0, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with a solid color, indicating that the formation is mainly composed of heavy oil and is evaluated as a pure oil layer; when the difference between the oil index F and the corrected water index g is small and they alternate in the formation, the gap between the oil index F and the corrected water index g of the formation in the fluid property identification effect diagram is filled with an alternating slash and solid color, indicating that the oil and water content in the formation is unstable and is evaluated as an oil and water layer.

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