Novel method for using acoustic logging p-wave and s-wave velocity estimates for water saturation in gas reservoirs

Abstract

This application relates to new systems and methods for quantifying hydrocarbon saturation using measured acoustic logs. The methods and systems herein are capable of accurately quantifying water saturation and hydrocarbon percentage in low resistivity, low contrast, shaly sand reservoirs where previous methods would indicate the reservoir to be water-bearing. In embodiments, the disclosed systems utilize acoustic logging equipment or tools and techniques to transmit and / or record acoustic signals. Acoustic logging equipment operates by generating acoustic signals and detecting the acoustic signals after they have passed through one or more geologic formations.

Description

[0001] Cross-references to related applications

[0002] This application claims the benefit of U.S. Patent Application No. 18 / 654,884, filed May 3, 2024, which claims the priority benefit of U.S. Provisional Application Series No. 63 / 563,884, filed March 11, 2024, pursuant to 35 USC §119, all of which are considered part of this application and are hereby incorporated by reference into the disclosure of this application. Technical Field

[0003] This disclosure generally relates to the fields of well logging interpretation and rock physical assessment of subsurface formations. Specifically, this disclosure describes a method for determining fluid saturation in subsurface formations that does not require the use of resistivity measurements. Background Technology

[0004] The amount of hydrocarbons is a crucial parameter when assessing the potential of hydrocarbon reservoirs. Prior to reservoir development, hydrocarbon content determines whether the reservoir contains a quantity of commercially viable material. Various methods and systems have been developed to determine hydrocarbon content before the expensive and time-consuming processes of drilling and extracting hydrocarbons from formations. Previous systems focused on determining the water content within a given subsurface space. Hydrocarbons occupy any space in the formation pores that is not occupied by water.

[0005] In conventional reservoirs, the primary method for estimating water saturation is the Archie saturation model. In pure sand and sandstone reservoirs, assuming known brine or formation water resistivity, the Archie saturation model has proven effective. The main assumption of the Archie saturation model is that formation resistivity is primarily a function of the electrical conductivity of the fluid filling the pore spaces.

[0006] The assumption that formation resistivity is primarily a function of the fluids filling the pore spaces is invalid in formations with a rock matrix composed largely of shale or other conductive minerals. In argillaceous sandstone and shale gas reservoirs with high saline conductivity (low saline resistivity), the Archie model can still be effective in determining water saturation. Other saturation models have been developed for cases with low salinity and high clay content, but they may not always be superior to the Archie model.

[0007] In conventional reservoirs, nuclear magnetic resonance (NMR) logging is an alternative method for fluid identification that does not require knowledge of formation resistivity (Rt) and brine resistivity (Rw). NMR logging allows for the quantification of fluid saturation, and with advancements in NMR drilling technology, two-dimensional (2D) NMR imaging has become possible for this purpose.

[0008] In unconventional reservoirs such as shale gas and tight gas sandstone, the application of NMR logging tools for fluid characterization faces limitations. These limitations stem from the low porosity and permeability of these unconventional reservoirs, making accurate measurements more challenging. Furthermore, the lower frequency of NMR logging tools compared to laboratory-based NMR equipment can also affect the accuracy and resolution of measurements. Another drawback of NMR logging tools is their relatively shallow lateral detection depth, for example, compared to resistivity and acoustic logging tools. Therefore, in the presence of significant mud invasion, NMR logging tools may fail to detect areas outside the flushed or invaded zones.

[0009] Besides NMR logging and other conventional measurement methods, subsurface formations can be characterized by several different parameters, including measurements of compression and shear waves. For water-bearing clastic reservoirs, there is a linear relationship between P-wave and S-wave velocities. When the fluids occupying the pore space of the reservoir are primarily gas or light oil, the bulk modulus of the formation is significantly affected, but the shear modulus remains relatively constant. This results in lower velocity ratios in gas or light oil siliceous clastic reservoirs. This concept is often used for fluid identification in the seismic interpretation of conventional reservoirs.

[0010] Existing techniques focus on qualitatively determining the presence of hydrocarbons based on lower velocity ratios associated with hydrocarbon reservoirs. Quantifying fluid saturation remains necessary in formations where conventional saturation models are ineffective and where the assumptions common to conventional saturation models are not made.

[0011] Accordingly, this application relates to novel systems and methods for quantifying hydrocarbon saturation using measured acoustic logging. Technological and operational improvements provide significantly enhanced results compared to previous methods and systems. The methods and systems described herein can accurately quantify water saturation and hydrocarbon percentage in low-resistivity, low-contrast argillaceous sandstone reservoirs, where previous methods would have indicated the reservoirs were water-bearing. The embodiments described herein can accurately estimate water and hydrocarbon saturation under a wider range of subsurface conditions. Attached Figure Description

[0012] Figure 1 It is a diagram of the oil and gas well environment, equipped with instruments for measuring, recording, and transmitting the characteristics of underground formations in oil and gas reservoirs.

[0013] Figure 2 This is a diagram of an acoustic borehole logging system used to obtain measurements of compression wave velocity (Vp) and shear wave velocity (Vs) within underground formations.

[0014] Figure 3 This is a flowchart of an embodiment of a system for determining the hydrocarbon potential of underground rock formations.

[0015] Figure 4This is a flowchart of an embodiment of a system for determining the Vp-Vs trend line for aqueous or fully saline saturated water in order to determine the hydrocarbon potential of underground reservoirs.

[0016] Figure 5 This is a diagram of an example embodiment of comparing P-wave velocity with S-wave velocity to determine water saturation.

[0017] Figure 6 These are well logs of reservoir data used in conjunction with the embodiments described herein.

[0018] Figure 7a This is a well logging chart of a argillaceous sandstone reservoir where conventional saturation models are ineffective in quantifying water saturation.

[0019] Figure 7b yes Figure 7a The P-wave and S-wave velocity intersection diagram of the indicated layer in the well logging chart.

[0020] Figure 8 According to the embodiments and Figure 1-7b The system combines a high-level functional block diagram of available controllers. Detailed Implementation

[0021] The following description is presented to enable those skilled in the art to make and use this disclosure, and is provided in the context of the patent application and its claims. Various modifications to the embodiments will be apparent to those skilled in the art, and the general principles herein can be applied to other embodiments. Therefore, this disclosure is not intended to be limited to the embodiments shown, but should be accorded the widest scope consistent with the principles and features described herein.

[0022] Acoustic signals can propagate through formations as compression and shear waves. These signals can be actively measured by transmitting and recording. The velocities of compression and shear waves depend on various formation parameters, such as lithology, degree of compaction and cementation, overlying stress, porosity, and type of saturated fluid. Generally, changes in these parameters cause a proportional increase or decrease in compression and shear velocities, except when gas or light oil (hydrocarbons) are present as fluids that partially or completely fill the pores. Introducing small amounts of hydrocarbons into the pore space leads to a significant decrease in compression velocity, especially when the hydrocarbons are gaseous, while increasing hydrocarbon saturation slightly increases the shear velocity. Improvements to conventional methods are achieved by measuring changes in these parameters and comparing the measurements with known or theoretical quantities.

[0023] In embodiments, the disclosed system utilizes acoustic logging equipment or tools and techniques to transmit and / or record acoustic signals. Acoustic logging equipment operates by generating acoustic signals and detecting them after they have passed through one or more geological formations. For example, acoustic signals can be generated and the time taken to receive the acoustic signals at a generation point or at one or more spaced-apart receivers can be recorded. Recording the travel time allows the calculation of the speed of sound through subsurface formations to characterize the formations. As described in the embodiments herein, acoustic logging tools can be used to generate and record acoustic signals.

[0024] Figure 1 and Figure 2 An exemplary embodiment depicts how the wellbore environment is prepared and acoustic data is recorded. A combination of hardware and software is used to process the received acoustic data into hydrocarbon potential.

[0025] Figure 1 An oil and gas well environment is depicted. System 100 includes an oil drilling rig 101, which provides the infrastructure for creating a borehole 109. System 100 is operated by a control system 102. The oil drilling rig 101 and control system 102 operate to create a borehole 109 into geological formation 104. As part of the drilling process for creating the borehole 109, drilling fluid is flushed into the borehole space 109a. Drill fluid is injected into the borehole 109 to remove drilled material. The drilling fluid penetrates the geological formation 104 adjacent to the borehole 109, displacing the native formation fluid. This penetration creates three sub-zones: an invasion zone 105, a transition zone 106, and an uninvaded zone 107.

[0026] The invasion zone 105 is the space where the drilling fluid has completely replaced the native fluid. Beyond the invasion zone 105 is a zone of partial replacement by the native fluid, referred to as the transition zone 106. Beyond the lateral depth of the transition zone, the native fluid occupying the formation's pore space is largely undisturbed by drilling and flushing processes. The undisturbed zone is the uninvaded zone 107.

[0027] In an exemplary embodiment, the measurements of compression and shear waves correspond to the unintruded zone 107. However, the permeability or porosity of geological formations can create large intruded or transitional zones. This increase in size would make it impossible for any acoustic measuring instrument to record compression and shear waves in the intruded or transitional zones.

[0028] exist Figure 1 In the diagram, the strip is depicted as a flat 2D rectangle with sharp edges. In practice, the strip exists in 3D space and has an annular cross-section. The distance radiating horizontally and vertically outward from the center of the borehole is called the lateral depth. At each borehole depth, there exists a horizontal plane perpendicular to the borehole depth direction. The lateral depth is any direction radiating outward from the center of the borehole within this plane. An example lateral depth is shown in... Figure 1The image is drawn in a 2D frame using thick arrows. The borehole depth is along the direction of borehole 109. The edge of each zone can vary with the borehole depth and along any lateral depth. Each zone has a cross-section in a plane at any given borehole depth. Depending on the precise composition of at least the geological features, the drilling fluid used, and the porosity of the geological rock, the cross-section of any zone can differ from an ideal annulus. Any measuring instruments used as part of the method or system described herein are lowered or moved into the wellbore to record information.

[0029] During operation, the acoustic measuring device is lowered through the wellbore. A motor for lowering the acoustic measuring device may be attached to the drilling rig 101. Alternatively, the motor for lowering the acoustic measuring device may be located near the drilling rig 101. The movement is continuous, and measurements are taken as the acoustic measuring device moves through different depths. To record information at a specific borehole depth, the acoustic measuring device is positioned at or near that specific borehole depth. Bringing the acoustic measuring device to a specific depth may be referred to as being adjacent to a specific subsurface feature level, positioned adjacent to a specific subsurface feature level, lowered into a hydrocarbon reservoir, or moved into a hydrocarbon reservoir. Bringing the acoustic measuring device to a specific depth includes moving the acoustic measuring device through the specific depth at a certain speed. Alternatively, the acoustic measuring device may be operated in a static position, moved intermittently, or a combination thereof.

[0030] Additional features not depicted may include a mud circulation system for the wellbore, drill pipe, and drill bit. Logging system 103 may include logging tools, surface and subsurface sensors, and instruments for measuring, recording, and transmitting subsurface formation characteristics of the oil and gas reservoir.

[0031] In an exemplary embodiment, one or more acoustic logging tools 108 may be lowered or moved into the borehole space 109a to the borehole depth of the geological formation 104. The one or more acoustic logging tools 108 may be positioned horizontally adjacent to the geological formation 104. Figure 1 This is an exemplary depiction of horizontally adjacent positioning. Alternatively, the acoustic logging tool may be positioned above, below, or at the same horizontal plane as the borehole depth of interest. Compression and shear data may be recorded by one or more acoustic logging tools 108. The recorded data is transmitted from one or more acoustic logging tools 108 to logging system 103, control system 102, or a combination thereof. The recorded data travels along the suspended acoustic logging tool 108 (… Figure 2 The acoustic logging tool 202 in the middle) transmits wires. Figure 1 The wires depicted may be shielded, insulated, or otherwise coated to protect the signal from the wellbore environment. As further described in other embodiments, the acoustic logging tool 108 may be lowered into the borehole 109 by a motor.

[0032] In addition to one or more acoustic logging tools 108, an additional logging tool 103a may be included at or near the surface. The additional logging tool 103a is connected to the logging system 103 or the control system 102 to transmit the recorded data. The operation of the logging system 103 is controlled by the control system 102. Figure 1 The control system 102 and logging system 103 are depicted as separate entities. The control system 102 may have a display and user input terminals. The logging system 103 may also have a display and user input terminals. In embodiments, the control system 102 and logging system 103 may be implemented in the same component or device. The control system 102 and logging system may include one or more processors connected to a memory for recording received data and accessing instructions. Method steps may be expressed as or stored as instructions in the memory. By accessing the instructions, system 100 improves operation to make a more accurate and reliable assessment of the water saturation and hydrocarbon potential of geological formations. The control system 102, logging system 103, or both may include... Figure 8 The controller 1900 is described in more detail below.

[0033] In some embodiments, acoustic logging tools can be used to measure compression and shear data of geological formations in the unintruded zone 107. In some embodiments, other surface or subsurface logging tools capable of recording compression and shear data can be used.

[0034] Figure 2 It is an acoustic borehole logging system used to obtain measurements of compression wave velocity (Vp) and shear wave velocity (Vs) in underground formations. Figure 2 The components are operated to measure subsurface formation characteristics to identify the hydrocarbon content of the formation according to embodiments herein. System 200 is an idealized representation of lowering an acoustic logging tool 202 into a borehole 203 via a cable 201. Operation of system 200 may be referred to as cable logging operation. Cable 201 extends from acoustic logging tool 202 across a pulley or trolley 205 and terminates in logging system 204. Logging system 204 includes control hardware and software for a drive motor 206. Motor 206 then rotates pulley or trolley 205. By rotating pulley or trolley 205 counterclockwise, acoustic logging tool 202 is lowered into borehole 203. Clockwise rotation raises acoustic logging tool 202. Logging system 204 houses a portion of cable 201. Cable 201 may be shielded, insulated, or otherwise coated to protect transmitted measurements from the wellbore environment. Acoustic measurements can be recorded by moving the acoustic logging tool 202 to or near the area of ​​interest in the subsurface. The acoustic logging tool 202 can be in the same horizontal plane as the measured borehole depth, above the measured borehole depth, or below the measured borehole depth.

[0035] The acoustic logging tool 202 includes one or more acoustic transmitters. The acoustic transmitters are located in... Figure 2 The transmitters are labeled T1, T2, and T3. There can be any number of transmitters. Each transmitter emits pulses of acoustic energy at regular intervals.

[0036] Acoustic logging tool 202 includes one or more acoustic receivers. For illustrative purposes, Figure 2 Three acoustic receivers are depicted, in Figure 2 The receivers are labeled R1, R2, and R3. Although three are shown, any number can be used. The acoustic receiver detects each of the pulses emitted by one or more acoustic transmitters and converts them into corresponding electrical signals. The corresponding electrical signals are transmitted via cable 201 to logging system 204. System 200 can be controlled by the hardware and software included in logging system 204 or by a control system not depicted. For example, system 200 can be controlled by, for example,... Figure 1 The control system 102 shown controls the process. The method steps can be expressed or stored as instructions in memory. By accessing these instructions, system 200 refines its operation to provide a more accurate and reliable assessment of the water saturation and hydrocarbon potential of geological formations. Logging system 204 may include... Figure 8 The controller 1900 is described in more detail below.

[0037] Figure 1 and Figure 2 This is an exemplary depiction of two operations involving lowering acoustic equipment into the wellbore and recording information. Figure 1 The acoustic logging tool 108 can be brought to the geological formation using a motor and pulleys or trolley attached to an oil drilling rig or similar infrastructure. Figure 1 The operation of a cable-guided acoustic logging tool can be referred to as cable logging operation. In some embodiments, the acoustic logging tool 108 can be attached to the wellbore as an oilfield tool. When the wellbore is drilled and flushed, the logging tool can be attached to the drill bit and follow the drill bit into the wellbore. Figure 1 The operation of attaching measuring tools to the drill bit or following the tubing after the drill bit can be called logging while drilling (LWD). Figure 1 In LWD, the structure of the acoustic logging tool 108 differs between LWD and wireline logging operations. In wireline logging, the acoustic logging tool is connected via a cable and transmits signals to the surface via wires. In LWD, the acoustic logging tool 108 is connected to the drill bit or tubing and transmits measured data in real time to the logging system 103 via mud pulse telemetry or other real-time data transmission methods, and stores the recorded acoustic data until it is returned to the surface. Figure 2 The system 200 in the middle performs similar measurements by removing the drilling equipment and using separate motors, pulleys or trolleys and control systems. Figure 2The operation of the system 200 can be referred to as cable logging operation. Given the content disclosed herein, those skilled in the art will recognize... Figure 1 and Figure 2 Features may have the same structural characteristics, or a structural characteristic of one of them may be used in the other. In some embodiments, a feature may be used in either or both. For example, the same structural characteristic, including an acoustic logging tool 202 comprising an acoustic receiver and an acoustic transmitter, may be used as... Figure 1 The acoustic logging tool 108 in the middle. For example, features that may be the same and / or switchable include logging system 204 that can be used with Figure 1 Control system 102 in Figure 1 The logging system 103 in this document is the same as or similar to both. Furthermore, given the disclosure herein, those skilled in the art will recognize that wireline operation and logging while drilling are different operating modes, but the steps involved in both methods can be the same. For example, both wireline operation and logging while drilling require measuring subsurface formations by generating and recording acoustic signals.

[0038] According to embodiments described herein, the acoustic measurement equipment may be stationary during recording, or preferably in motion while traversing underground space. Furthermore, a single measurement may be performed at each borehole depth, or a series of repeated measurements may be performed at each borehole depth. In some embodiments, a trend line may be created from the recorded measurements by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. While a single measurement can provide data points, multiple measurements are required to create a trend line.

[0039] Figure 3 This is a flowchart of an embodiment of a system for determining the hydrocarbon potential of subsurface geological formations. Method 300 includes steps for determining the water saturation of hydrocarbon reservoirs in order to estimate hydrocarbon potential. Figure 3 The steps in the process are performed by the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. Used to perform... Figure 3 Exemplary hardware embodiments of the intermediate steps include Figure 1 The acoustic logging tool 108, control system 102, and logging system 103 in the middle, and Figure 2Acoustic logging tool 202 and logging system 204 are used. At S301, the acoustic logging tool measures compression and shear waves in a geological formation suspected of containing hydrocarbons. The tool records compression acoustic logging (DTC) and shear acoustic logging (V). When the fluid occupying the pore space in the formation is mainly gas or light oil, the bulk modulus of the formation is significantly affected, but the shear modulus remains relatively constant. Replacing some water in the reservoir's pore space with hydrocarbons causes a significant decrease in P-wave velocity (compression wave velocity), especially when the hydrocarbon is gas, while the S-wave velocity (shear wave velocity) only increases slightly, resulting in lower Vp / Vs observed in hydrocarbon-bearing intervals.

[0040] According to embodiments described herein, further drilling and hydrocarbon transport equipment can be provided. The equipment may include one or more pipes, one or more pumps, and a control system for controlling further drilling and transport. After acoustic logging tools have completed measurements, any equipment required for further drilling and transporting hydrocarbons to the surface can be installed. After measuring and determining water and / or hydrocarbon saturation based on the systems and methods included herein, the system can display an indication to extract hydrocarbons from the subsurface formation if a sufficient amount of hydrocarbons is detected. The system can enable the extraction of one or more hydrocarbons from a hydrocarbon reservoir. By more accurately characterizing the amount of hydrocarbons in the hydrocarbon reservoir before extraction, the system can be able to make more economical extraction decisions. For example, using… Figure 2 The embodiments depicted herein allow for the bringing of further hydrocarbon extraction equipment to the wellbore for further drilling and extraction. For example, utilizing... Figure 1 The embodiments depicted suggest that further drilling and extraction can be performed using the on-site drilling rig 101 and other equipment, or further hydrocarbon extraction equipment can be brought to the wellbore for further drilling and extraction. Alternatively, new boreholes can be drilled to reach the hydrocarbon reservoir. One or more pipes can be inserted into the hydrocarbon reservoir to transport hydrocarbons to the surface.

[0041] Method 300 includes optional steps S302 and S302a-c. In S302, a quality check of the data may be performed by an acoustic logging tool (such as acoustic logging tool 202), one or more processors connected to the acoustic logging tool, or a combination of both. In S302, the measured data is compared by the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both, with known data for hydrocarbon reservoirs with similar geological formations or from adjacent wells. The measurements have been affected by washout, or the measurements may be concentrated in transition or invasion zones.

[0042] In S303, Equations 1 and 2 use the measured values ​​from S301 or the values ​​corrected as in optional steps S302 and S302a-c, and convert the measured values ​​into shear rate (Vs) and compression rate (Vp).

[0043] Equation 1 Vp = 304.8009 / DTC

[0044] Equation 2 Vs = 304.8009 / DTS

[0045] S303 is executed by the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both.

[0046] In S304, a baseline trend line is created by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both, for comparison with measured values. The amount of water present in a given volume ranges from 0% to 100%. 0% water is completely dry or completely hydrocarbon. The 100% dry / hydrocarbon baseline is referred to as the completely dry trend or completely hydrocarbon saturation trend. 100% water or brine is completely brine saturated. The 100% water / brine baseline is referred to as the completely brine trend or completely brine saturation trend. First, Vs and Vp need to be determined for each of the completely dry trend and the completely brine trend. Estimated data or previously measured data can be used. More accurate final results (i.e., water saturation and hydrocarbon potential) can be determined by using theoretical or empirical data that closely matches the geological formation of interest. For example, a processor can calibrate the completely brine saturation trend to theoretical or empirical data.

[0047] For example, reservoirs with similar geological characteristics and completely brine saturated near the hydrocarbon reservoir of interest can be used. Known completely brine saturated intervals can be measured by acoustic logging tools, one or more processors connected to the acoustic logging tools, or a combination of both, and used as a completely brine baseline. A completely hydrocarbon saturation trend can be obtained from the completely brine trend by means of fluid displacement. In cases where completely brine intervals are lacking in the subsurface reservoir, empirical trends can also be used. For example, for a completely brine baseline, the trend line can be estimated using Equations 3 and 4. Equations 5 and 6 are empirical estimates of Vp and Vs for completely dry or completely gas saturated conditions, from which a completely dry trend line can be determined.

[0048] Equation 3

[0049] Equation 4

[0050] Equation 5

[0051] Equation 6

[0052] Where C is the volume of clay and This refers to total porosity. Equations 3-6 can be used by acoustic logging tools, one or more processors connected to the acoustic logging tools, or a combination of both to calibrate the full brine saturation trend line. Calibration can increase the accuracy of any water saturation or hydrocarbon saturation determination.

[0053] Equations 7 and 8 are used by acoustic logging tools, one or more processors connected to the acoustic logging tools, or a combination of both to create fully hydrocarbon-saturated trend lines and fully saline trend lines, respectively.

[0054] Equation 7

[0055] Where x and y are the P-wave and S-wave velocities, respectively, a0 is the coefficient of Vp, b0 is the coefficient of Vs, and c0 is the intercept of the complete drying trend.

[0056] Equation 8

[0057] Where x and y are the velocities of the P-wave and S-wave, respectively, and a 100 It is the coefficient of Vp, b 100 It is the coefficient of Vs, and c 100 It is the intercept of the complete saltwater trend.

[0058] In alternative embodiments, the coefficients may include other values. For example, a0 and a 100 It can be a coefficient of bulk modulus (KB), a0 and a 100 These can be coefficients of Vp / Vs, b0 and b 100 These can be the coefficients of DTS, b0 and b 100 It can be a coefficient of DTC, or a combination thereof.

[0059] In S305, the vertical distances of the compression wave velocity and shear wave velocity from the baseline trends of the complete brine and complete hydrocarbon are determined by the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. Figure 5 This is an exemplary demonstration of S305. The solid line represents the Vp-Vs trend at full hydrocarbon saturation. The black dashed line represents the Vp-Vs regression trend at 100% brine saturation. Equations 9 and 10 are used by acoustic logging tools, one or more processors connected to the acoustic logging tools, or a combination of both to determine vertical distances.

[0060] Equation 9

[0061] Where D0 is the distance of the data point from the complete hydrocarbon trend.

[0062] Equation 10

[0063] Where D 100This is the distance of the data point from the full saltwater trend. Any value above or below the trend line will be set to 0% or 100%, respectively.

[0064] In S306, water saturation is determined by the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both, based on the distance between the trend lines determined in S305. The percentage of water saturation for VsVp data points at a given borehole depth is determined by the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both, using Equation 11.

[0065] Equation 11

[0066] Swt represents the percentage of water saturation.

[0067] Equation 11 can be replaced by equations 9 and 10 to give equation 12.

[0068] Equation 12

[0069] Further replacements or rearrangements of these items were also envisioned.

[0070] S305, S306, or a subset thereof, may be referred to as determining the deviation. By determining the deviation between the upper and lower baseline trends, the user can determine the position of the sample of interest relative to the baseline. This principle is demonstrated by performing exemplary steps S305 and S306. S305 and S306, including determining the deviation, are executed by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. Exemplary hardware embodiments for executing S305 and S306, including determining the deviation, include... Figure 1 Acoustic logging tool 108, control system 102 and logging system 103 and Figure 2 Acoustic logging tool 202 and logging system 204.

[0071] If additional data is available, then steps S307 and S307a are optional. If core water saturation is available, then water saturation at various depths can be fitted to these measured quantities. Fitting data to previously known data to improve the accuracy of the current measurement can be performed by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. If core water saturation data is available, the trend with the most uncertainty (typically a fully hydrocarbon-saturated trend) can be slightly adjusted to obtain a match with the core data, if necessary. Core water saturation is obtained from one or more core samples removed from the geological formation. The drill bit is used to remove a cylindrical section of the subsurface formation. The cylindrical section is the core sample. Water saturation can be accurately measured from the cylindrical sample. A processor connected to one or more measuring tools can determine the water content of the core sample. The water content determined by the processor can be fed to the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. The water content from the excavated core sample can be fed to the acoustic logging tool or a processor connected to the acoustic logging tool during the recording operation, or it can be used by the processor to adjust the results at some point after the recording is completed. For example, core analysis can take a month or longer, and the determined water content is then used by the processor to adjust the data.

[0072] Water saturation is given by Equation 11 or Equation 12. Hydrocarbon presence refers to the volume percentage not occupied by brine / water. To convert from water saturation to hydrocarbon saturation, use Equation 13.

[0073] Equation 13 Sh = 1–Swt

[0074] Where Sh is the hydrocarbon saturation.

[0075] Figure 4 This is a flowchart of an embodiment of a system for determining a complete saline trend line to determine the hydrocarbon potential of a subsurface reservoir. To determine the water saturation percentage, upper and lower trend lines are determined for the geological strata of interest. Different methods may be used to determine the trend line, depending on the composition of the geological strata. Figure 4 The steps in the process are performed by the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. Used to perform... Figure 4 Exemplary hardware embodiments of the steps include Figure 1 The acoustic logging tool 108, control system 102, and logging system 103 in the middle, and Figure 2 Acoustic logging tool 202 and logging system 204.

[0076] Method 400 is an exemplary process for determining a complete saline trend line using an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination thereof. In S401, the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination thereof, determines whether a complete saline segment exists in the reservoir. A segment is a space or volume within a geological formation. In S401, if a segment exists, compression and shear waves can be measured by the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination thereof, which gives the trend line of the complete saline trend line. Measuring the segment and determining the trend line is step S401a.

[0077] In S402, no fully saline interval is available. Further determination of the geological formation characteristics is required. If adjacent well data is available, then equations 3-6 can be used in step 402a by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both.

[0078] If adjacent well data is unavailable, then fluid displacement to 100% brine saturation is required. S403 and S404 respectively include fluid displacement and trend line determination. Methods known in the art can be used for fluid displacement. Fluid displacement can be performed by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both.

[0079] Figure 6 This is an exemplary graphical depiction of the hydrocarbon potential in geological strata. Figure 6 Column 6 is labeled Vp / Vs. Column 6 provides a visual representation of the hydrocarbon potential based on the embodiments described herein. In column 6, two lines form an envelope, with the dark shaded area defining the interior of the envelope. The first line is the velocity ratio calculated from measured compression and shear sonic logging. The second line is the velocity ratio estimated from a complete brine trend line assuming the reservoir is completely brine saturated. The separation between the two lines—the dark shade—indicates the presence of hydrocarbons in the reservoir. The thicker the dark portion of the envelope, the greater the proportion of hydrocarbons present at the corresponding depth.

[0080] Figure 6 Column 7 is labeled SWT. Column 7 provides a visual representation of the water saturation of the geological formations based on the embodiments described herein. Column 7 is read from left to right as water saturation from 100% to 0%. Visual inspection reveals the region of highest water saturation (approximately 3950 meters, see column 1) corresponding to the thinnest envelope in column 6. Column 4 is the measured resistivity, which is also used in conventional saturation models to estimate the hydrocarbon potential in the geological formations. Columns 2 and 5 are used to determine other formation properties, such as lithology and porosity.

[0081] Figure 1-4The methods and systems described were applied to datasets taken from argillaceous sandstone reservoirs. The results, along with data obtained and processed using conventional techniques, are presented in [the table / document / etc.]. Figure 7a middle. Figure 7a It is a well logging diagram. Figure 7b It is Figure 3 and Figure 4 Some of the steps applied to Figure 7a A graphical representation of the dataset presented in the image. Used for creating... Figure 7a and Figure 7b A brief description of some of the steps. First, compression and shear data are recorded (S301), and Vp and Vs are calculated from the compression and shear sonic logging data (S303). Next, the complete saline saturation trend line of the reservoir is determined (S304). [The text then abruptly shifts to a different topic:] Turning... Figure 4 The processor detects the presence of an aquifer and determines that it is not a fully aquifer (S401). The processor relies on empirical data to calculate the full saltwater saturation trend line (S402) and (S402a). Return to... Figure 3 Given a determined trend line for complete salt water saturation, the processor performs a fluid displacement to 100% hydrocarbon saturation to determine a trend line for complete hydrocarbon saturation (S304). The processor determines the vertical distance of each data point from both the salt water saturation trend line and the hydrocarbon saturation trend line (S305). Figure 7b This is a visual depiction of S305. The processor determines water saturation (S306) and hydrocarbon saturation. The processor plots the data and provides it in... Figure 7a The image depicted in the text is shown. Figure 7a The first column is gamma-ray logging. Gamma-ray logging can be used to identify lithology. Figure 7a The second column is resistivity logging. Resistivity logging is the primary method used to quantify water saturation in conventional saturation models. Figure 7a Column 3 is neutron porosity. Neutron logging is represented by the dashed curve in column 3. Bulk density is also represented by the dashed line in column 3. Both bulk density and neutron porosity are used to determine porosity—the percentage of pore space within a reservoir or formation. Figure 7a Column 4 contains DTS and DTC. For example, for... Figure 1-4 As with the methods and systems described above, the measuring tools record DTC and DTS. DTC is represented by a solid line in column 4. DTS is represented by a dashed line in column 4. The speed ratio (Vp / Vs) is in column 5. The water saturation percentage is in column 6.

[0082] exist Figure 7a In the diagram, the vertical axis represents the borehole depth. The columns are plotted based on the borehole depth. Figure 7aThe lower line at 701 indicates a 100% water-bearing reservoir below this depth. Above line 702, hydrocarbons and water or brine coexist in the pore spaces. The embodiments described herein provide systems and methods for distinguishing hydrocarbons from water or brine in the pore spaces. Previous methods indicated that the formation was 100% water-saturated. This is depicted by the vertical dashed line on the right side of column 6. However, bracketed portion 701 represents a known gas reservoir. For example, Archie's method, which relies in part on changes in formation resistivity, misses gas intervals in bracketed portion 701. The embodiments included herein improve the user's ability to accurately identify hydrocarbon intervals, in which previous models have been inadequate.

[0083] Figure 7b This is an example cross plot of Vp and Vs, with data from... Figure 7a The trend line and data. Data point 704 corresponds to the data below line 702. Data point 703 corresponds to the data in parentheses 701. Figure 7b The angled dashed line in the diagram represents a trend line of complete saline saturation. Data point 704 clustered at the dashed line indicates that the formation at the corresponding depth has pore spaces filled only with water or saline. Figure 7b The angled solid line in the diagram represents the complete hydrocarbon trend line. Data point 703, enclosed in a circle, clusters in the space between the complete hydrocarbon trend line and the complete brine saturation trend line. Data point 703 indicates that the pore space at the corresponding depth is partly water or brine and partly hydrocarbon. Data point 703 indicates content missed by previous methods.

[0084] Method 400 provides steps for determining fully saline intervals, performed by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both, under various formation conditions. (This is for...) Figure 7a and 7b The formations in the argillaceous sandstone reservoirs provided in the data offer an example application. These reservoirs contain fully salt-saturated sections. In this example, according to... Figure 4 The flowchart executes S401 and S401a. In cases where aquifer intervals are lacking within the reservoir, it can be obtained from... Figure 4 The flowchart in the diagram determines the appropriate trend. After determining the complete brine trend, the complete hydrocarbon saturation trend can be determined using Gassmann or Biot fluid displacement.

[0085] In an embodiment, Figure 1-4The examples described can be used to determine that subsurface formations may not contain any sufficient amount of hydrocarbons for extraction. In negative information scenarios, similar steps are performed to characterize the subsurface formation. Aquifer sections can be measured by acoustic logging tools, one or more processors connected to the acoustic logging tools, or a combination of both, or empirical comparisons can be made. However, hydrocarbon-bearing sections will not be measured because the subsurface formation lacks sufficient amounts of hydrocarbons for extraction. Deviations from brine and hydrocarbon trend lines are edge cases. The recorded compression and shear waves will give the velocity at or near the full brine saturation trend line. Users will be interested in gaining knowledge about the lack of sufficient amounts of hydrocarbons subsurface, as this will save significant time and money.

[0086] According to the embodiments described herein, Figure 1-4 The systems and methods described can be implemented entirely based on velocity ratios and measured compression or shear sonic logging, rather than in the Vp-Vs space. Figure 1-4 The system and method can be implemented by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. Equations 7 and 8 can be constructed in some form to allow either P-wave or S-wave velocity to be the dependent variable. Equation 14, given below, is an expression where P-wave velocity is the dependent variable.

[0087] Equation 14

[0088] Where a is the slope of the regression trend and c is the intercept of the regression trend.

[0089] Dividing both sides of Equation 14 by the S-wave velocity, we obtain an expression in the form of velocity ratio and shear wave travel time or slowness. This is given below as Equation 15.

[0090] Equation 15

[0091] Here again, b and d are the intercept and slope of the new equation, respectively. And... This is shear sonic logging. The velocity ratio can be determined directly from the measured compression and shear sonic logging data by dividing the measured shear sonic logging data by the measured compression sonic logging data, using the acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both. Equation 15 can be determined for both complete brine saturation and complete hydrocarbon saturation trends, and then... Figure 3 Equation 15 is used in the flowchart to estimate water saturation by an acoustic logging tool, one or more processors connected to the acoustic logging tool, or a combination of both.

[0092] To highlight the separation between the fully brine trend and the fully hydrocarbon saturated trend, especially in unconventional oil reservoirs, this model can also be implemented entirely based on the P-wave modulus (or bulk modulus) and shear modulus by acoustic logging tools, one or more processors connected to the acoustic logging tools, or a combination of both. Both the P-wave modulus and the shear modulus are given by the following equation: Equation 17

[0093] Equation 18

[0094] Where M is the P-wave modulus, G is the shear modulus, and... It is the measured bulk density. P-wave modulus, bulk modulus, and shear modulus are examples of elastic modulus.

[0095] As with Vp and Vs, the regression trend that correlates G with M can also be determined.

[0096] Equation 19

[0097] Where a is the slope of the regression trend and c is the intercept of the regression trend.

[0098] Equation 19 can also be determined for the trends of complete brine and complete hydrocarbon saturation, as in Equations 7 and 8, and then applied in... Figure 3 The flowchart is used to determine water saturation. For example, a0 and a 100 It can be a coefficient of M, and b0 and b 100 It can be a coefficient of G. Equation 19 can be applied to acoustic logging tools, one or more processors connected to the acoustic logging tools, or a combination of both. Figure 3 Used in the steps described above.

[0099] The embodiments included herein improve the operation and determination of hydrocarbon saturation estimation compared to previous methods. The methods and systems included herein can be executed on one or more computer systems, which may include one or more processors, memory, and interfaces for input and control. The methods and systems operate using a combination of hardware and software to perform the steps described in the various embodiments. Instructions for performing the method steps may be stored in a non-transitory computer-readable medium. Figure 8A high-level functional block diagram of a controller 1900, usable in conjunction with embodiments herein, is depicted. The controller 1900 includes input / output terminals 1910, a processor 1902, and a memory 1904. The input / output terminals 1910, processor 1902, and memory 1904 are connected via a bus 1908. The memory 1904 includes instructions 1906 and other data 1916. Information in the form of electrical impulses is passed between the input / output terminals 1910, processor 1902, and memory 1904 to perform operations of the controller 1900. The input / output terminal 1910 may be a display, touchscreen, mouse, keyboard, or wired or wirelessly connected to another device. The instructions 1906 may include steps for executing functions or algorithms using the processor 1902.

Claims

1. A system for estimating the hydrocarbon saturation of a hydrocarbon reservoir, wherein at least one oil drilling rig is operated at the hydrocarbon reservoir to create a first wellbore in the hydrocarbon reservoir, the system comprising: Acoustic logging system, the acoustic logging system comprising: Motor and cable, or drill bit and at least one drill rod; and An acoustic measurement device, which is positioned horizontally adjacent to the hydrocarbon reservoir within the wellbore; Processor, wherein the processor is configured to: Measure the compression wave of the hydrocarbon-bearing section within the first underground reservoir; Measure the shear waves across the hydrocarbon-bearing section of the first subsurface reservoir; Determine the velocity of the compression wave in the hydrocarbon-bearing section; Determine the velocity of the shear wave in the hydrocarbon-bearing section; Determine the full brine saturation trend for hydrocarbon reservoirs; Determine the complete hydrocarbon saturation trend for hydrocarbon reservoirs; The water saturation of hydrocarbon reservoirs is determined based on the deviations of the compression wave velocity and shear wave velocity of hydrocarbon-bearing sections from the complete brine saturation trend and the complete hydrocarbon saturation trend; and The hydrocarbon saturation of the hydrocarbon reservoir is estimated based on the determined water saturation.

2. The system of claim 1, wherein the processor is further configured to: Measuring compression waves in the aquifer section within a hydrocarbon reservoir; and Shear waves are measured across the aquifer section of the second subsurface reservoir, wherein the trend toward complete brine saturation is determined based on the compressive waves and measured shear waves measured across the aquifer section of the second subsurface reservoir, and the trend toward complete hydrocarbon saturation is determined at least in part based on fluid displacement to 100% hydrocarbon saturation.

3. The system of claim 2, wherein the processor is further configured to determine the full brine saturation trend based on a calibration of the empirical full brine shale trend or the empirical full brine sandstone trend.

4. The system of claim 3, wherein calibration is based on one or more of the following: ， ， ,as well as Where V s_100 It is the shear rate of the empirically fully saline shale trend, V p_100 It is the compression rate of the fully brine shale trend, V s_0 It is an empirical estimate of the shear rate of completely dried argillaceous sandstone, V p_0 It is an empirical estimate of the compression rate of completely dry argillaceous sandstone, where C is the clay volume, and It is the total porosity.

5. The system of claim 1, wherein the complete brine saturation tendency and the complete hydrocarbon saturation tendency are determined based on velocity ratio and shear sonic logging or velocity ratio and compression sonic logging.

6. The system of claim 5, wherein the determined water saturation is based on: Where a0 is V p / V s The coefficient of V, where V p It is the velocity of the compressed wave and V s is the shear wave velocity; b0 is the coefficient of shear acoustic logging (DTS), c0 is the intercept of the complete hydrocarbon saturation trend; a 100 It is V p / V s The coefficient of V, where V p It is the velocity of the compressed wave and V s It is the shear wave velocity, b 100 It is the coefficient of DTS, c 100 It is the intercept of the tendency for complete salt water saturation, and Swt is the water saturation fraction of the total pore space at each lateral depth; or Where a0 is the coefficient of bulk modulus (KB), b0 is the coefficient of shear modulus G, c0 is the intercept of the tendency for complete hydrocarbon saturation, and a 100 It is the coefficient of KB, b 100 It is the coefficient of G; c 100 It is the intercept of the tendency for complete salt water saturation, and Swt is the water saturation fraction of the total pore space at each lateral depth; or Where a0 is V p The coefficient of V, where V p is the velocity of the compressed wave, and b0 is the coefficient of Vs, where V s It is the shear wave velocity, c0 is the coefficient of the tendency for complete hydrocarbon saturation; a 100 It is V p The coefficient of V, where V p It is the velocity of the compressed wave, b 100 It is V s The coefficient of V, where V s It is the shear wave velocity, c 100 It is a coefficient of the tendency for complete salt water saturation, and Swt is the water saturation fraction of the total pore space at each lateral depth; or Where a0 is V p / V s The coefficient of V, where V p It is the velocity of the compressed wave and V s is the shear wave velocity, b0 is the coefficient of compression acoustic logging (DTC), c0 is the intercept of the complete hydrocarbon saturation trend, and a 100 It is V p / V s The coefficient of V, where V p It is the velocity of the compressed wave and V s It is the shear wave velocity, b 100 It is the coefficient of DTC, c 100 It is the intercept of the tendency for complete salt water saturation, and Swt is the water saturation fraction of the total pore space at each lateral depth.

7. The system of claim 1, further comprising a display and instructions for displaying hydrocarbon saturation for at least a portion of the hydrocarbon reservoir.

8. The system of claim 1, wherein the tendency for complete salt water saturation and the tendency for complete hydrocarbon saturation are determined based on the elastic modulus calculated from the measured compression wave and the measured shear wave.

9. The system of claim 1, wherein the system is configured to be applied to a seismic body to quantify hydrocarbon saturation in a subsurface reservoir.

10. The system of claim 1, further comprising: The first pipeline utilizes equipment installed at the well site to transport at least one hydrocarbon from the hydrocarbon reservoir.

11. The system of claim 1, further comprising: the estimated hydrocarbon saturation of the hydrocarbon reservoir as a fraction of the total pore space and determined by the following formula: Hydrocarbon saturation = 1– Swt .

12. The system of claim 1, wherein the motor is attached to the oil drilling rig.

13. The system of claim 1, wherein the acoustic measurement device transmits a first acoustic energy pulse and receives a second acoustic energy pulse.

14. A method for estimating the hydrocarbon saturation of gas and oil reservoirs, the method comprising: Create wellbores in hydrocarbon reservoirs; Move the acoustic measurement equipment to a location within the hydrocarbon reservoir; Measure the compression wave of the hydrocarbon-bearing section within the first underground reservoir; Measure the shear waves across the hydrocarbon-bearing section of the first subsurface reservoir; Determine the velocity of the compression wave in the hydrocarbon-bearing section; Determine the velocity of the shear wave in the hydrocarbon-bearing section; Determine the full brine saturation trend for hydrocarbon reservoirs; Determine the complete hydrocarbon saturation trend for hydrocarbon reservoirs; The water saturation of a hydrocarbon reservoir is determined by the deviation of the compression wave velocity and shear wave velocity of the hydrocarbon-bearing section from the complete salt water saturation trend and the complete hydrocarbon saturation trend. as well as The hydrocarbon saturation of the hydrocarbon reservoir is estimated based on the determined water saturation.

15. The method of claim 14, further comprising: Inserting a first pipeline into a hydrocarbon reservoir to transport at least one hydrocarbon; and Transport of at least one hydrocarbon from a hydrocarbon reservoir.

16. The method of claim 14, further comprising, wherein the determined water saturation is based on Where a0 is V p The coefficient of V, where V p It is the velocity of the compressed wave, b0 is V s The coefficient of V, where V s It is the shear wave velocity, c0 is the coefficient of complete hydrocarbon saturation tendency, and a 100 It is V p The coefficient, b 100 It is V s The coefficient, c 100 It is a coefficient representing the tendency of salt water to become fully saturated, and Swt is the percentage of water saturation.

17. The method of claim 16, further comprising: the estimated hydrocarbon saturation of the hydrocarbon reservoir is a percentage of hydrocarbon saturation and is determined by the following formula: Hydrocarbon saturation = 1– Swt .

18. The method of claim 17, further comprising displaying a percentage of hydrocarbon saturation for at least a portion of the hydrocarbon reservoir.

19. The method of claim 14, wherein the acoustic measuring device transmits a first acoustic energy pulse and receives a second acoustic energy pulse.

20. A non-transitory computer-readable medium storing instructions, which, when executed by a processor, cause the processor to perform operations including: Measure the compression wave of the hydrocarbon-bearing section within the first underground reservoir; Measure the shear waves across the hydrocarbon-bearing section of the second subsurface reservoir; Determine the velocity of the compression wave in the hydrocarbon-bearing section; Determine the velocity of the shear wave in the hydrocarbon-bearing section; Determine the full brine saturation trend for hydrocarbon reservoirs; Determine the complete hydrocarbon saturation trend for hydrocarbon reservoirs; The water saturation of a hydrocarbon reservoir is determined by the deviation of the compression wave velocity and shear wave velocity of the hydrocarbon-bearing section from the complete salt water saturation trend and the complete hydrocarbon saturation trend. as well as The hydrocarbon saturation of the hydrocarbon reservoir is estimated based on the determined water saturation.

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