Method, application, medium and equipment for discriminating oil reservoir production condition of bottom water heavy oil reservoir developed by SAGD (Steam Assisted Gravity Drainage)

Abstract

The invention discloses an SAGD (Steam Assisted Gravity Drainage) developed bottom water heavy oil reservoir oil layer production condition distinguishing method, application, a medium and equipment. The method comprises the steps that the formation resistivity of an original oil reservoir of a target layer, the formation resistivity after the oil reservoir is used and the interval transit time are measured through a logging series; determining a porosity value of the reservoir based on the interval transit time; determining the numerical value of the rock-electricity coefficient of the oil reservoir; a preset model of resistivity and saturation is determined based on the numerical value of the rock electricity coefficient, and then the resistivity of bound water in the original oil reservoir stratum is determined; according to a preset model of the fluid resistivity and the temperature, the formation water resistivity after the oil reservoir is used is determined; and according to a preset model of the resistivity and the saturation, the determined formation water resistivity after the oil reservoir is used and other known parameters, the oil saturation after the oil reservoir is used is determined. The technology can be used for quantitatively judging the production condition of the oil layer below the SAGD production well of the bottom water reservoir, and provides a basis for determining the detailed deployment position of a submerged well location for the bottom water reservoir.

Description

Technical Field

[0001] The present invention relates to the technical field of petroleum exploration, and in particular to a method, application, medium and equipment for distinguishing the production status of an oil layer in a bottom water heavy oil reservoir developed by SAGD. Background Art

[0002] SAGD (steam-assisted gravity drainage) oil recovery technology is a cutting-edge technology for the international development of super-heavy oil. Its principle was originally based on the principle of water injection and salt recovery. This technology is a method of injecting steam into the oil reservoir from a vertical well or a horizontal well above the horizontal production well near the bottom of the reservoir, and the heated crude oil and steam condensate are produced from the horizontal well at the bottom of the reservoir. This technology has become a mature technology. Since its introduction into China in 1997, it has formed the largest SAGD production base in China in Liaohe Oilfield, and has formed Liaohe's characteristic technology of vertical and horizontal combination SAGD adapted to continental sedimentation. After more than 20 years of development, the SAGD steam chamber has been formed, and the Xing VI Formation of Liaohe D84 block has risen to the top of the oil layer. After experiencing the steam chamber formation and steam lateral expansion stage, it is currently entering the steam chamber decline stage. Traditional thinking holds that during the SAGD development process, a steam cavity is formed around the steam injection well above the SAGD horizontal production well due to the steam overlay effect, and the oil layer above the SAGD horizontal production well is mainly utilized, while the oil layer below is less utilized. However, the temperature measurement curve shows that the temperature below the SAGD production horizontal well increases to varying degrees, and there is a "slope" in the temperature measurement curve. This may be due to the temperature increase caused by heat conduction and the oil layer has not been utilized, or it may be due to the temperature increase caused by steam wave and the oil layer has been utilized for development. At present, it is impossible to determine whether the oil layer below the SAGD production well in the bottom water heavy oil reservoir has been utilized.

[0003] Patent document CN106442757A discloses a method for determining oil and water layers. In this method, the oil and gas display layer is determined by using rock cuttings, cores, well wall coring and gas logging data, and the relative percentages of C8-C37 normal alkanes, Pt and Ph are obtained. The positions of Pr / C17, Ph / C18, ∑C21- / ∑C22+, C21+C22 / C28+C29 on the rock pyrolysis gas chromatography characteristic parameter chart are calculated to determine the reservoir fluid properties. This invention expands the application range of parameters and improves the interpretation compliance rate of oil and water layers in logging. However, this method is only applicable to the identification of oil and water layers in the original reservoir state, and cannot determine the situation after the thermal recovery heavy oil reservoir has been used.

[0004] Patent document CN108894778B discloses a method for identifying the fluid properties of oil and gas layers using gas logging data. In this method, the gas logging data of the corresponding depth of the fluid sample is used to obtain the gas logging identification parameters Bh*10+sz-wh, c1 / (c2+c3+c4+c5) of the oil and gas layer; a gas logging identification chart is constructed: c1 / (c2+c3+c4+c5) is selected as the horizontal coordinate and Bh*10+sz-wh is selected as the vertical coordinate, and plotted on the coordinate chart. This method can quickly identify oil and gas layers without downhole fluid sampling, reducing exploration and development costs, but it cannot determine the oil layer utilization of SAGD developed oil reservoirs.

[0005] Patent document CN102518424A discloses a composite fluid resistivity and temperature measurement device. The device is a well logging measurement device for downhole fluid resistivity and temperature parameters, comprising: a pressure-bearing body, a composite sensor, and a safety protection plug-in. The pressure-bearing body comprises an upper pressure-bearing end cover, a lower pressure-bearing end cover, and a pressure-bearing shell, and the upper pressure-bearing end cover and the lower pressure-bearing end cover are connected to the pressure-bearing shell; the composite sensor comprises a group of resistivity sensors, a temperature sensor, and a composite sensor body, the temperature sensor is between the group of resistivity sensors, and the group of resistivity sensors and the temperature sensor are connected to the composite sensor under pressure and sealed; the composite sensor and the safety protection plug-in are connected to the pressure-bearing body through a mounting hole, and the safety protection plug-in is connected to the composite sensor. The device has not yet been industrialized, and due to limited investment funds, there are thousands of wells in the oil field block development, and it is impossible to monitor each well every day, which delays oil field production.

[0006] Patent document CN105649588A discloses a method for developing heavy oil reservoirs using SAGD. This method optimizes the setting of multiple vertical wells to assist steam injection wells, selects the best steam injection time and the best key production parameters, achieves uniform development of SAGD steam chambers, maximizes oil layer production, and improves recovery. However, this method does not mention the quantitative method and judgment method of the oil saturation decline in the produced oil reservoir, and cannot guide the potential adjustment in the later stage of SAGD development.

[0007] The currently disclosed technologies for super heavy oil SAGD do not involve a method for determining the oil layer production status of the produced oil reservoirs of super heavy oil SAGD. Summary of the invention

[0008] The present invention provides a method, application, medium and equipment for distinguishing the production status of oil layers in a bottom water heavy oil reservoir developed by SAGD, so as to solve at least one of the above-mentioned technical problems existing in the prior art.

[0009] In order to achieve the above technical objectives, the technical solution adopted by the present invention is as follows:

[0010] According to one aspect of the present invention, a method for determining the production status of a bottom water heavy oil reservoir developed by SAGD is provided, comprising the following steps:

[0011] Step 1: Use the logging series to measure the formation resistivity R of the original reservoir in the target layer t1 , formation resistivity R after reservoir production t2 , sound wave time difference Δt;

[0012] Step 2: Determine the reservoir porosity value Φ based on the acoustic wave time difference Δt t , where the porosity value Φ t Including the original reservoir porosity value Φ t1 and the porosity value Φ after reservoir production t2 ;

[0013] Step 3: Determine the value of the rock electrical coefficient of the reservoir;

[0014] Step 4: Determine the preset model of resistivity and saturation based on the value of the rock electrical coefficient, and calculate the preset model of resistivity and saturation, the original reservoir oil saturation S1, and the porosity value Φ of the original reservoir. t1 and the original reservoir formation resistivity R t1 , determine the irreducible water resistivity R in the original reservoir formation w1 ;

[0015] Step 5: Based on the preset model of fluid resistivity and temperature, the original reservoir state formation temperature t1, and the bound water resistivity R in the original reservoir formation w1 , the formation temperature t2 after the oil reservoir is produced determines the formation water resistivity R after the oil reservoir is produced w2 ;

[0016] Step 6: Based on the preset model of resistivity and saturation, the porosity value Φ after the reservoir is produced t2 , formation resistivity R after reservoir production t2 And the formation water resistivity R after reservoir production determined in step 5 w2 Determine the oil saturation S2 after the reservoir is produced.

[0017] According to one embodiment of the present invention, in step 2, the reservoir porosity value Φ is determined based on the acoustic wave time difference Δt. t Including using core pressure test to analyze the relationship between porosity and acoustic time difference regression to obtain the reservoir porosity value Φ t .

[0018] According to one embodiment of the present invention, the porosity value Φ of the reservoir is obtained by analyzing the relationship between porosity and acoustic time difference regression using a core pressure test. tWhen the core pressure test data is corrected for overburden pressure, the porosity of the core analysis is corrected to the formation porosity.

[0019] According to one embodiment of the present invention, the core pressure test data includes porosity and permeability obtained by coring measurements.

[0020] According to one embodiment of the present invention, in step 2, the reservoir porosity value Φ is determined based on the acoustic wave time difference Δt. t Including calculating the reservoir porosity value Φ based on the following formula (1): t :

[0021] Φ t =(Δt-Δt ma ) / (Δt f -Δt ma )*1 / C p -V sh *(Δt sh –Δt ma ) / (Δt f -Δt ma )……(1)

[0022] Where:

[0023] Φ t - porosity calculated by sonic wave;

[0024] Δt——the acoustic time difference logging value of the target layer;

[0025] Δt ma ——Sound wave time difference of rock skeleton;

[0026] Δt f ——Sound wave time difference of formation fluid;

[0027] C p ——Acoustic compaction correction factor;

[0028] V sh —— formation mud content;

[0029] Δt sh ——The acoustic time difference value of pure mudstone.

[0030] According to one embodiment of the present invention, the rock electrical coefficients of the oil reservoir determined in step 3 include a lithology coefficient a related to lithology, a constant b related to lithology, a cementation index m, and a saturation index n.

[0031] According to one embodiment of the present invention, in step 3, the rock electrical coefficients a, b, m, and n of the oil reservoir are determined by core experiments.

[0032] According to one embodiment of the present invention, if the rock resistivity experimental analysis data is incomplete in step 3, the saturation coefficient is derived using the saturation, porosity, and rock resistivity of the core analysis.

[0033] According to one embodiment of the present invention, the rock resistivity is obtained by deep lateral logging at the situ location.

[0034] According to one embodiment of the present invention, the preset model of resistivity and saturation in step 4 is determined based on Archie's formula, and the preset model is the following formula (2):

[0035]

[0036] According to one embodiment of the present invention, the original reservoir oil saturation S1 in step 4 is determined via core experiments.

[0037] According to one embodiment of the present invention, the preset model of fluid resistivity and temperature in step 5 is determined based on the Aps formula, and the preset model of fluid resistivity and temperature is the following formula (3):

[0038] R w2 =R w1 ((t1+21.5) / (t2+21.5)) (3)

[0039] According to one embodiment of the present invention, the formation temperature t1 in the original reservoir state and the formation temperature t2 after the reservoir is produced are measured via well temperature logging.

[0040] According to one embodiment of the present invention, the oil saturation S2 after the reservoir is produced in step S6 is determined by the following formulas (4) and (5):

[0041]

[0042]

[0043] According to one embodiment of the present invention, the formation resistivity R after the oil reservoir is produced in step S6 t2 It is the deep direction resistivity value measured in the logging series in the later stage of SAGD development.

[0044] According to another aspect of the present invention, there is provided a method for distinguishing the oil layer production status of a bottom water heavy oil reservoir developed by SAGD as described above, and its application in bottom potential tapping in the later stage of SAGD development.

[0045] According to one embodiment of the present invention, a method for distinguishing the production status of a bottom water heavy oil reservoir developed by SAGD is used to determine detailed potential tapping well deployment locations.

[0046] According to one embodiment of the present invention, the oil saturation value of each point from below the SAGD production horizontal well to the original oil-water interface is determined based on the method for distinguishing the oil layer utilization of the bottom water heavy oil reservoir developed by SAGD, and the oil saturation value of the lower limit of reservoir deployment>35% is used as the basis for determining the specific deployment position of the SAGD bottom potential well.

[0047] According to another aspect of the present invention, there is provided a computer-readable storage medium storing a computer program, wherein the computer program, when executed by a processor, performs the steps of the method for determining the oil stratum production status of a bottom water heavy oil reservoir developed by SAGD as described above.

[0048] According to another aspect of the present invention, there is provided a computer device, comprising:

[0049] at least one processor; and

[0050] A memory storing a computer program executable on the processor, wherein the processor executes the steps of the method for determining the oil layer production status of a bottom water heavy oil reservoir developed by SAGD as described above when executing the program.

[0051] Due to the adoption of the above technical scheme, the method, application, medium and equipment provided by the present invention have the following beneficial effects compared with the prior art: using the technical scheme described in the present invention, the utilization of the oil layer below the bottom water super heavy oil SAGD production horizontal well that has been mobilized can be accurately judged, and when bottom potential is tapped in the later stage of SAGD development, a detailed basis for the deployment of potential tapping wells is provided. This method has been successfully implemented and applied in the bottom water super heavy oil reservoir of the Xing VI formation in the D84 block, accurately identifying the oil-water layer below the SAGD production horizontal well, and deploying potential tapping wells in the oil layer, with a daily output of more than 10t / d. BRIEF DESCRIPTION OF THE DRAWINGS

[0052] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the following specific embodiments, they are used to explain the present invention but do not constitute a limitation of the present invention. In the accompanying drawings:

[0053] Figure 1 A schematic diagram of uniaxial correction of porosity and permeability according to an embodiment of the present invention is shown;

[0054] Figure 2 A schematic diagram showing the relationship between rock electrical fully saturated water resistivity according to an embodiment of the present invention is shown;

[0055] Figure 3 A schematic diagram of the relationship between the increase of rock saturated oil resistance according to an embodiment of the present invention is shown. DETAILED DESCRIPTION

[0056] In order to make the purpose, technical solution and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with specific embodiments. It should be understood that the specific embodiments described herein are only used to explain the present invention and are not used to limit the present invention.

[0057] Steam Assisted Gravity Drainage (SAGD) is a technology for developing super-heavy oil. For high-viscosity crude oil that has no flow capacity under the original conditions of the formation, the oil layer preheating stage is required to achieve thermal connectivity between the injection and production wells. After the thermal connectivity is formed, the injected steam overlaps upward to form a steam chamber in the formation. The steam chamber moves upward and laterally, exchanging heat with the crude oil in the oil layer. The heated crude oil and steam condensate are discharged to the production well below by gravity.

[0058] The determination of oil-water layers is one of the core issues in the study of oil reservoir geology. The present invention analyzes the relationship between resistivity and dissolved salt concentration through the conductivity of the material, the multiplier of the ion concentration converted into equivalent sodium chloride concentration, and the Arps formula and Archie formula to jointly derive the relationship between fluid resistivity, salinity and temperature, thereby determining the matching relationship between the heat generated by the injected steam and the resistivity during the SAGD development process, quantitatively determining the degree of oil layer utilization in the bottom water reservoir, and solving the actual production problems of the oil field.

[0059] In one embodiment of the present invention, a method for determining the oil layer production status of a bottom water heavy oil reservoir developed by SAGD is provided. The method generally comprises the following steps:

[0060] Step 1: Use the logging series to measure the formation resistivity R of the original reservoir in the target layer t1 , formation resistivity R after reservoir production t2 , sound wave time difference Δt;

[0061] Step 2: Determine the reservoir porosity value Φ based on the acoustic wave time difference Δt t , where the porosity value Φ t Including the original reservoir porosity value Φ t1 and the porosity value Φ after reservoir production t2 ;

[0062] Step 3: Determine the value of the rock electrical coefficient of the reservoir;

[0063] Step 4: Determine the preset model of resistivity and saturation based on the value of the rock electrical coefficient, and calculate the preset model of resistivity and saturation, the original reservoir oil saturation S1, and the porosity value Φ of the original reservoir. t1 and the original reservoir formation resistivity R t1 , determine the irreducible water resistivity R in the original reservoir formation w1 ;

[0064] Step 5: Based on the preset model of fluid resistivity and temperature, the original reservoir state formation temperature t1, and the bound water resistivity R in the original reservoir formation w1 , the formation temperature t2 after the oil reservoir is produced determines the formation water resistivity R after the oil reservoir is produced w2 ;

[0065] Step 6: Based on the preset model of resistivity and saturation, the porosity value Φ after the reservoir is produced t2 , formation resistivity R after reservoir production t2 And the formation water resistivity R after reservoir production determined in step 5 w2 Determine the oil saturation S2 after the reservoir is produced.

[0066] Each step is described in detail below.

[0067] In step S1, the formation resistivity R of the original reservoir of the target layer is measured by using the well logging series. t1 , formation resistivity R after reservoir production t2 , acoustic wave time difference Δt. These parameters can be measured by selecting a suitable logging series according to conventional technical requirements in the field, and will not be described in detail here.

[0068] In step 2, the reservoir porosity value Φ is obtained t , porosity value Φ t Including the original reservoir porosity value Φ t1 and the porosity value Φ after reservoir production t2 There are many different methods to obtain the reservoir porosity value Φ t In some embodiments, the porosity value Φ of the reservoir is obtained by analyzing the relationship between porosity and acoustic wave time difference regression using a core pressure test. t In this case, since the core analysis is generally conducted at normal ground pressure (or a certain specific pressure), the pores will expand, so the measured core porosity and permeability will be greater than the porosity under formation conditions. Therefore, it is necessary to correct them and perform overburden correction on the core pressure test data to correct the core analysis porosity to the formation porosity. The specific correction operation will be introduced in the specific examples below. In some other embodiments, the reservoir porosity value Φ is obtained based on the following formula (1): t :

[0069] Φ t =(Δt-Δt ma ) / (Δt f -Δt ma )*1 / C p -V sh *(Δt sh –Δt ma ) / (Δtf -Δt ma )……(1)

[0070] Where Φ t is the porosity calculated by acoustic wave, Δt is the acoustic time difference logging value of the target layer, and Δt ma is the acoustic time difference of the rock skeleton, Δt f is the acoustic time difference of the formation fluid, C p is the acoustic compaction correction factor, V sh is the formation mud content, Δt sh is the pure mudstone acoustic wave time difference value. In other embodiments, the above two methods can be used to simultaneously obtain the reservoir porosity value Φ t , and then use the comparison of the two results for correction.

[0071] In step 3, the value of the rock electrical coefficient of the reservoir is determined. The determined rock electrical coefficient of the reservoir includes the lithology coefficient a related to lithology, the constant b related to lithology, the cementation index m and the saturation index n. The rock electrical coefficients a, b, m and n of the reservoir can be determined by core experiments. If the rock resistivity experimental analysis data is incomplete, the saturation coefficient is derived using the saturation, porosity and rock resistivity of the core analysis, where the rock resistivity can be obtained by deep lateral logging at the homing location.

[0072] In step 4, the preset model of resistivity and saturation is first determined based on the values ​​of rock electrical coefficients a, b, m, and n. The preset model of resistivity and saturation is determined based on Archie's formula, and the preset model is the following formula (2):

[0073]

[0074] The original reservoir oil saturation S1, the original reservoir porosity Φ t1 and the original reservoir formation resistivity R t1 Substituting into the above formula (2), the bound water resistivity R in the formation under the original reservoir state can be determined w1 The original reservoir oil saturation S1 was determined through core experiments.

[0075] The relationship between fluid resistivity and temperature is: when the formation temperature rises, the activity of fluid ion movement increases, the conductivity of the fluid (formation water in the reservoir) increases, and the resistivity in the reservoir decreases, which is reflected in the fact that the resistivity actually measured in the logging series is lower than the resistivity in the original reservoir state. Therefore, in step 5, the preset model of fluid resistivity and temperature is determined based on the Aps formula, and the preset model is shown in the following formula (3):

[0076] R w2 =R w1((t1+21.5) / (t2+21.5)) (3)

[0077] The original reservoir state formation temperature t1, the irreducible water resistivity R w1 , the formation temperature t2 after the reservoir is produced is substituted into formula (3) to determine the formation water resistivity R after the reservoir is produced w2 The original reservoir state formation temperature t1 and the reservoir production formation temperature t2 are measured by well temperature logging.

[0078] In step S6, according to the preset model of resistivity and saturation determined by Archie's formula, it can be inferred that the oil saturation S2 after the reservoir is produced conforms to the following formula (4):

[0079]

[0080] After sorting, we get:

[0081]

[0082] The porosity value after the reservoir is produced is Φ t2 , formation resistivity R after reservoir production t2 And the formation water resistivity R after reservoir production determined in step 5 w2 Substitute into formula (5) to determine the oil saturation S2 after the reservoir is produced. The formation resistivity R after the reservoir is produced t2 Measured by the logging series, this resistivity can be the deep direction resistivity value measured in the logging series in the later stage of SAGD development. The porosity value after the reservoir is produced is Φ t2 It can be determined according to the method provided in step 2.

[0083] The present invention also provides an application of the above-mentioned method for distinguishing the production status of the bottom water heavy oil reservoir developed by SAGD when bottom potential is tapped in the later stage of SAGD development. The method for distinguishing the production status of the bottom water heavy oil reservoir developed by SAGD provides a basis for determining the detailed deployment location of the potential tapping well. According to the method for distinguishing the production status of the bottom water heavy oil reservoir developed by SAGD, the oil saturation value of each point from the bottom of the SAGD production horizontal well to the original oil-water interface is determined, and the oil saturation value of the lower limit of the reservoir deployment>35% is used as the basis for determining the specific deployment location of the SAGD bottom potential tapping well. When it is desired to determine the oil saturation of a certain point in the target layer in the later stage of SAGD development, the method is used to calculate the oil saturation value of each point from the bottom of the SAGD production horizontal well to the original oil-water interface, and the specific deployment location of the SAGD bottom potential tapping well is determined according to the oil saturation of the lower limit of the reservoir deployment>35%, so as to fully utilize the reserves below the SAGD production horizontal well.

[0084] The present invention also provides a computer-readable storage medium storing a computer program, which, when executed by a processor, executes the steps of the method for determining the oil layer production status of a bottom water heavy oil reservoir developed by SAGD as described above.

[0085] The present invention also provides a computer device, which includes at least one processor and a memory, wherein the memory stores a computer program that can be run on the processor, and when the processor executes the program, the steps of the method for determining the oil layer utilization status of the bottom water heavy oil reservoir developed by SAGD as described above are executed.

[0086] The implementation scheme of the present invention is introduced below in conjunction with specific application examples.

[0087] The D84 block Xing VI bottom water super-heavy oil reservoir began to be put into steam huff and puff development in 1997, and was transferred to SAGD development in 2006. It has been thermally recovered for more than 20 years. The thickness of the oil layer below the SAGD horizontal well is 15-35 meters from the oil-water interface. Taking the D84-Ping 44 to D84-Ping 47 well group as an example, the current oil saturation of a certain point below the D84-Ping 44 to D84-Ping 47 well group is calculated, that is, the residual oil saturation. In this example, the residual oil saturation of 10m directly below the D84-Ping 45 well in the D84-Ping 44 to D84-Ping 47 well group is calculated.

[0088] According to the logging data, the lateral formation resistivity at 10m below Well D84-Ping 45 is R t1 =78Ω.m, the formation resistivity R of the reservoir after SAGD development was measured in the logging series t2 is 1.272414.

[0089] In determining the porosity value of the reservoir, Φ t In this example, the relationship between core analysis porosity and acoustic time difference regression is directly used to obtain the reservoir porosity value Φ t . Since the core analysis is generally conducted under normal ground pressure (or a certain pressure), the pores will expand, so the measured core porosity and permeability will be greater than the porosity under formation conditions, so it is necessary to correct them. First, after the core porosity and permeability are measured, the experimental data are sorted and mathematically analyzed to obtain the following correction formula for porosity changes with pressure:

[0090] Φ c =Φ0*P e -0.06

[0091] K c =K0^P e -0 .75

[0092] Where: Φ0—ground porosity (%)

[0093] K0—ground permeability (mD)

[0094] P e —Net overburden pressure (MPa).

[0095] The porosity analysis of core pressure test is carried out under triaxial loading conditions, while the actual formation conditions can be regarded as uniaxial deformation. Therefore, the porosity measured in the laboratory needs to be converted and corrected into the porosity under uniaxial pressure. The specific conversion formula is:

[0096] Φ f =Φ s -(Φ s -Φ z )r(S-1)

[0097] Where: Φ f —Converted uniaxial porosity (%)

[0098] Φ s — Ground porosity (%)

[0099] Φ z —Triaxial porosity measured in the laboratory (%)

[0100] r—conversion factor, which is related to the Poisson's ratio of rock and is taken as 0.619.

[0101] The triaxial porosity and permeability measured in the laboratory are divided by the ground porosity and ground permeability, respectively, and the porosity variation coefficient Φ is plotted in the same coordinate system. i / Φ0, coefficient of variation of permeability K i The relationship curve between / K0 and overburden pressure is shown in the attached figure. Figure 1 As shown. Perform uniaxial correction on porosity and permeability. The correction steps are as follows:

[0102] a) Calculate the net overburden pressure of the sample based on the sample depth and reservoir pressure, and then Figure 1 Determine the position of A on the horizontal axis;

[0103] b) From position A, the vertical intersection of curve 1 at point B yields the coefficient of variation of the triaxial porosity Φ zr , using Φ zr Multiplying by the ground porosity gives the triaxial porosity.

[0104] c) Calculate the uniaxial porosity Φ according to formula S-1 f ;

[0105] d)Φ fDivide by the ground porosity to get the uniaxial porosity variation coefficient Φ fk , find the corresponding point C on curve 1;

[0106] e) From point C, the curve 2 intersects vertically downward at point D. The intersection point is the uniaxial permeability variation coefficient K fr ;

[0107] f) K fr Multiplying it by the ground permeability gives the uniaxial permeability value.

[0108] The net overburden pressure is defined as:

[0109] P e =P s -P f

[0110] Among them, P s is the overlying formation pressure, P f is the pore fluid pressure, in MPa.

[0111] By calculating using the above method, the formation porosity and permeability data measured in the experiment are restored to the porosity and permeability values ​​under formation conditions.

[0112] According to formula S-2, calculate the mud content:

[0113]

[0114] Among them, GCUR—regional experience coefficient, taken as 3.7;

[0115]

[0116] SHH—shale indicator curve (conditional unit);

[0117] SHMN—SHH value at pure sandstone, generally 0 (conditional unit);

[0118] SHMX—SHH value at pure mudstone, generally taken as 40 (conditional unit).

[0119] Most of the wells in the block involved in this example use domestic CNC logging series, so the porosity is calculated using acoustic time difference and neutron gamma curve. However, the measured value of neutron gamma curve is relatively small and is greatly affected by the environment. In addition, the neutron gamma curve measurement depth of some wells is not deep enough, so the porosity is calculated using acoustic time difference in this area. The total porosity of the formation is calculated using formula S-3.

[0120] Acoustic formation factor method

[0121] The effective porosity of the formation is calculated using the sonic mud correction method, and the formula is shown in Formula S-4.

[0122] Where:

[0123] V SH - clay content;

[0124] t sh -Sonic time difference of pure mudstone;

[0125] t ma -Pure sandstone sonic time difference skeleton value.

[0126] In this example, due to incomplete data of some wells in the neutron gamma curve, the range of values ​​is small, and the relationship with the shale content and median particle size is not very good. Therefore, the permeability is calculated only using the shale content and porosity, see formula S-5.

[0127]

[0128] Where:

[0129] P-pore structure index;

[0130] R w - Formation water resistivity;

[0131] S w - water saturation;

[0132] R t - deep lateral resistivity;

[0133] R o -Resistivity of rock saturated with water;

[0134] K-permeability;

[0135] F-stratigraphic factors;

[0136] P f -Pore structure comprehensive index and formation factor conversion coefficient.

[0137] It turns out that:

[0138] PERM=0.162*exp(0.3522*PORR) (S-6)

[0139] Where: PORR-effective porosity (%);

[0140] PERM-Permeability (md).

[0141] Determine the value of the rock electrical coefficient of the reservoir. Since the rock resistivity test analysis data in this example is not systematic, the saturation coefficient is derived based on the saturation, porosity, and rock resistivity (deep lateral direction at the retrieval location) of the core analysis. First, find the relationship between R0 and porosity based on the core resistivity analysis data, and then calculate m = 1.75, a = 1 (see attached Figure 2 ); then based on this relationship and the porosity and saturation of the core analysis, n = 1.9 and b = 1 were calculated (see Appendix Figure 3 ).

[0142] The preset model of resistivity and saturation is determined according to the values ​​of rock electrical coefficients a, b, m, and n, as shown below:

[0143]

[0144] R t1 =78Ω.m,Φ t1 =0.347, S1=0.65 Substitute into formula S-7 to obtain R w1 =2.1.

[0145] R w1 Substitute the values ​​of t1=40 and t2=80 into the preset model of fluid resistivity and temperature as shown below:

[0146] R w2 =R w1 ((t l +21.5) / (t2+21.5)) (S-8)

[0147] Calculate the current formation water resistivity R w2 =2.1*[(40+21.5) / (80+21.5)]=1.272414.

[0148] The current oil saturation S2 is then calculated using the following formula S-8:

[0149]

[0150] Where a = 1, b = 1, m = 1.75, n = 1.9, R t2 =25,Φ t2 =0.347, R w2 =1.272414. The current oil saturation S2 is calculated to be 0.50, that is, the current oil saturation is 50%. The current oil saturation of each point below the D84-Ping 44 to D84-Ping 47 well group is calculated using the above method.

[0151] In the late stage of SAGD development of Xing VI Group in D84 Block, the oil saturation limit of well location deployment is greater than 35% within 10m below D84-Ping 44 ~ D84-Ping 47 well group, so the potential tapping horizontal well D84-Xing H56 well is deployed below the SAGD production horizontal wells of D84-Ping 44 ~ D84-Ping 47 well group. The potential tapping well has been implemented on site and has been put into production for more than 5 years, with an average single well daily oil production of more than 15 tons and a cumulative oil production of more than 23,000 tons. Another well SAGD bottom potential tapping horizontal well D84-Xing H62-1 well has also been put into production for more than 3 months, with an average single well daily oil production of more than 10 tons. The production effect of the SAGD bottom potential tapping well is very good, indicating that the invention method can serve the actual production.

[0152] The preferred embodiments of the present invention are described in detail above. However, the present invention is not limited to the specific details in the above embodiments. Within the technical concept of the present invention, a variety of simple modifications can be made to the technical solution of the present invention, and these simple modifications all belong to the protection scope of the present invention.

[0153] It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. In order to avoid unnecessary repetition, the present invention will not further describe various possible combinations.

[0154] In addition, various embodiments of the present invention may be arbitrarily combined, and as long as they do not violate the concept of the present invention, they should also be regarded as the contents disclosed by the present invention.

Claims

1. A method for determining the oil layer production status of a bottom water heavy oil reservoir developed by SAGD, characterized in that: The following steps are involved: Step 1: Use the logging series to measure the formation resistivity R of the original reservoir in the target layer t1 , formation resistivity R after reservoir production t2 , sound wave time difference Δt; Step 2: Determine the porosity value Φ of the reservoir based on the acoustic wave time difference Δt t , where the porosity value Φ t Including the original reservoir porosity value Φ t1 and the porosity value Φ after reservoir production t2 ; Step 3: Determine the value of the rock electrical coefficient of the reservoir; Step 4: Determine the preset model of resistivity and saturation based on the value of the rock electrical coefficient, and calculate the preset model of resistivity and saturation according to the preset model of resistivity and saturation, the oil saturation S1 of the original reservoir, and the porosity value Φ of the original reservoir. t1 and the formation resistivity R of the original reservoir t1 , determine the irreducible water resistivity R in the original reservoir formation w1 ; Step 5: Based on the preset model of fluid resistivity and temperature, the original reservoir state formation temperature t1, and the bound water resistivity R w1 , the formation temperature t2 after the oil reservoir is produced determines the formation water resistivity R after the oil reservoir is produced w2 ; Step 6: Based on the preset model of resistivity and saturation, the porosity value Φ of the reservoir after production t2 , formation resistivity R after reservoir production t2 and the formation water resistivity R after the oil reservoir is produced determined in step 5 w2 Determine the oil saturation S2 after the reservoir is produced.

2. The method according to claim 1, characterized in that In step 2, the reservoir porosity value Φ is determined based on the acoustic wave time difference Δt. t Including using core pressure test to analyze the relationship between porosity and acoustic time difference regression to obtain the reservoir porosity value Φ t .

3. The method according to claim 2, characterized in that The porosity value Φ of the reservoir is obtained by analyzing the relationship between porosity and acoustic time difference regression using the core pressure test. t When the core pressure test data is corrected for overburden pressure, the porosity of the core analysis is corrected to the formation porosity.

4. The method according to claim 3, characterized in that The core pressure test data includes porosity and permeability obtained by coring measurements.

5. The method according to claim 1, characterized in that In step 2, the reservoir porosity value Φ is determined based on the acoustic wave time difference Δt. t Including calculating the reservoir porosity value Φ based on the following formula (1): t : F t =(Δt-Δt ma ) / (Δt f -Δt ma )*1 / C p -V sh *(Δt sh –Δt ma ) / (Δt f -Δt ma )……(1) Where: Φ t - porosity calculated by sonic wave; Δt——the acoustic time difference logging value of the target layer; Δt ma ——Sound wave time difference of rock skeleton; Δt f ——Sound wave time difference of formation fluid; C p ——Acoustic compaction correction factor; V sh —— formation mud content; Δt sh ——The acoustic time difference value of pure mudstone.

6. The method according to claim 1, characterized in that The rock electrical coefficients of the oil reservoir determined in step 3 include a lithology coefficient a related to lithology, a constant b related to lithology, a cementation index m and a saturation index n.

7. The method according to claim 6, characterized in that In step 3, the rock electrical coefficients a, b, m, and n of the reservoir are determined through core experiments.

8. The method according to claim 7, characterized in that In step 3, if the rock resistivity experimental analysis data is incomplete, the saturation coefficient is derived using the saturation, porosity, and rock resistivity from the core analysis.

9. The method according to claim 8, characterized in that The rock resistivity is obtained by deep lateral logging at the situ location.

10. The method according to claim 1, characterized in that The preset model of resistivity and saturation in step 4 is determined based on Archie's formula, and the preset model is the following formula (2):

11. The method according to claim 1, characterized in that: The original reservoir oil saturation S1 in step 4 is determined through core experiments.

12. The method according to claim 1, characterized in that The preset model of fluid resistivity and temperature in step 5 is determined based on the Aps formula, and the preset model of fluid resistivity and temperature is the following formula (3): R w2 =R w1 ((t1+21.5) / (t2+21.5)) (3)。 13. The method according to claim 12, characterized in that The original reservoir state formation temperature t1 and the reservoir production-post formation temperature t2 are measured via well temperature logging.

14. The method according to claim 1, characterized in that The oil saturation S2 of the oil reservoir after production in step S6 is determined by the following formulas (4) and (5):

15. The method according to claim 14, characterized in that The formation resistivity R after the oil reservoir is produced in step S6 t2 It is the deep directional resistivity value measured in the logging series in the later stage of SAGD development.

16. An application of the method for distinguishing the oil layer production status of a bottom water heavy oil reservoir developed by SAGD according to any one of claims 1 to 15 in bottom potential tapping in the later stage of SAGD development.

17. The use according to claim 16, characterized in that The method for distinguishing the oil stratum production status of the bottom water heavy oil reservoir developed by SAGD is used to determine the detailed deployment locations of the potential tapping wells.

18. The use according to claim 17, characterized in that According to the method for distinguishing the oil stratum utilization of the bottom water heavy oil reservoir developed by SAGD, the oil saturation value of each point from the bottom of the SAGD production horizontal well to the original oil-water interface is determined, and the oil saturation value of the lower limit of reservoir deployment>35% is used as the basis for determining the specific deployment position of the SAGD bottom potential tapping well.

19. A computer-readable storage medium storing a computer program, characterized in that: When the computer program is executed by a processor, the steps of the method for determining the oil layer production status of a bottom water heavy oil reservoir developed by SAGD according to any one of claims 1 to 15 are performed.

20. A computer device comprising: at least one processor; as well as A memory storing a computer program executable on the processor, wherein the processor executes the steps of the method for determining the oil layer production status of a bottom water heavy oil reservoir developed by SAGD as described in any one of claims 1 to 15 when executing the program.

Images